SB-2/A 1 a2024975zsb-2a.txt SB-2/A As filed with the Securities and Exchange Commission on September 8, 2000 Registration No. 333-44130 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ------------------------------------ PRE-EFFECTIVE AMENDMENT NO. 1 TO FORM SB-2 REGISTRATION STATEMENT Under The Securities Act of 1933 ------------------------------------ ATLAS AMERICA PUBLIC #9 LTD. (Exact name of Registrant as Specified in its Charter) 311 ROUSER ROAD MOON TOWNSHIP, PENNSYLVANIA 15108 (412) 262-2830 (Address and Telephone Number of Principal Executive Offices and Principal Place of Business) ------------------------------------ JAMES R. O'MARA, PRESIDENT ATLAS RESOURCES, INC. 311 ROUSER ROAD, MOON TOWNSHIP, PENNSYLVANIA 15108 (412) 262-2830 (Name, Address and Telephone Number of Agent for Service) ------------------------------------ Copies to: WALLACE W. KUNZMAN, JR., ESQ. JAMES R. O'MARA KUNZMAN & BOLLINGER, INC. ATLAS RESOURCES, INC. 5100 N. BROOKLINE 311 ROUSER ROAD SUITE 600 MOON TOWNSHIP, PENNSYLVANIA 15108 OKLAHOMA CITY, OKLAHOMA 73112 ------------------------------------ Approximate Date of Commencement of Proposed Sale to the Public; AS SOON AS PRACTICABLE AFTER THIS REGISTRATION STATEMENT BECOMES EFFECTIVE. If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box: /X/ ------------------------------------
CALCULATION OF REGISTRATION FEE ---------------------------------------------------------------------------------------------- ---------------------------------------------------------------------------------------------- Proposed Proposed Title of Each Dollar Maximum Maximum Amount of Class of Securities Amount Offering Aggregate Registration to be Registered to be Registered Price per Unit Offering Price Fee ---------------------------------------------------------------------------------------------- Units (1) $15,000,000 $10,000 $15,000,000 $3,960 ----------------------------------------------------------------------------------------------
(1) "Units" means the Limited Partner interests and the Investor General Partner interests offered to Participants in the Partnership. THE REGISTRANT HEREBY AMENDS THE REGISTRATION STATEMENT ON SUCH DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE SECURITIES ACT OF 1933 OR UNTIL THIS REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a), MAY DETERMINE. ATLAS AMERICA PUBLIC #9 LTD. CROSS REFERENCE SHEET PURSUANT TO RULE 404
Item of Form SB-2 Caption in Prospectus ----------------- --------------------- 1. Front of Registration Statement and Outside Front Cover of Prospectus.................................... Front Page of Registration Statement and Outside Front Cover Page of Prospectus 2. Inside Front and Outside Back Cover Pages of Prospectus Inside Front and Outside Back Cover Pages of Prospectus 3. Summary Information and Risk Factors................... Summary of the Offering; Risk Factors 4. Use of Proceeds........................................ Capitalization and Source of Funds and Use of Proceeds 5. Determination of Offering Price........................ Not Applicable 6. Dilution............................................... Not Applicable 7. Selling Security Holders............................... Not Applicable 8. Plan of Distribution................................... Plan of Distribution 9. Legal Proceedings...................................... Litigation 10. Directors, Executive Officers, Promoters and Control Persons................................................ Management 11. Security Ownership of Certain Beneficial Owners and Management............................................. Management 12. Description of Securities.............................. Summary of the Offering; Terms of the Offering; Summary of Partnership Agreement 13. Interest of Named Experts and Counsel.................. Legal Opinions; Experts 14. Disclosure of Commission Position on Indemnification for Securities Act Liabilities......................... Fiduciary Responsibilities of the Managing General Partner 15. Organization Within Last Five Years.................... Management 16. Description of Business................................ Proposed Activities; Management 17. Management's Discussion and Analysis or Plan of Operation.............................................. Proposed Activities 18. Description of Property................................ Proposed Activities A. Issuers Engaged or to Be Engaged in Significant Mining Operations............................... Not Applicable B. Supplementing Financial Information about Oil and Gas Producing Activities.................... Not Applicable 19. Certain Relationships and Related Transactions......... Compensation; Management; Conflicts of Interest 20. Market for Common Equity and Related Stockholder Matters................................................ Not Applicable 21. Executive Compensation................................. Management 22. Financial Statements................................... Financial Information Concerning the Managing General Partner and the Partnership 23. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.................... Not Applicable
The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the SEC is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted. Preliminary Prospectus Dated September __, 2000 ATLAS AMERICA PUBLIC #9 LTD. - General and Limited Partner Interests at $10,000 per Unit - $1,000,000 (100 Units) Minimum Aggregate Capital Contributions - $15,000,000 (1,500 Units) Maximum Aggregate Capital Contributions - Atlas America Public #9 Ltd., a - The Offering: limited partnership, is managed by Atlas Resources, Inc. of Total Total Pittsburgh, Pennsylvania, and will Per Unit Minimum Maximum be funded to drill primarily -------- ------- ------- natural gas development wells. Public Price $10,000 $1,000,000 $15,000,000 - The units will be offered on a Dealer-manager fee, $1,000 $ 100,000 $ 1,500,000 "best efforts" "minimum-maximum" sales commissions, and basis. This means the reimbursement for broker-dealers must sell at least accountable due 100 units in order for this diligence expenses offering to close, and they are required to use only their best Proceeds to partnership $9,000 $ 900,000 $13,500,000 efforts to sell the remaining 1,400 units. Thus, this offering may close even though all of the 1,500 ------------ units offered have not been sold. - All subscription proceeds will be held in an interest bearing escrow account until 100 units have been sold. This offering will close on or before December 31, 2000, and will not be extended. If subscriptions for $1 million are not received by the offering termination date, then your subscription will be promptly returned to you from the escrow account with interest and without deduction for any fees.
--------------------------------------- THESE SECURITIES ARE SPECULATIVE AND ARE SUBJECT TO CERTAIN RISKS. (See "Risk Factors," Page 2.) NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. TABLE OF CONTENTS
Page SUMMARY OF THE OFFERING...........................................................................................1 Atlas America Public #9 Ltd...................................................................................1 Description of Units..........................................................................................1 Investor General Partner Units..........................................................................1 Limited Partner Units...................................................................................2 RISK FACTORS......................................................................................................2 Special Risks of the Partnership..............................................................................2 No Guarantee of Return of Investment or Rate of Return on Investment Because of Speculative Nature of Drilling Oil and Gas Wells....................................................................2 Risk That a Well Does Not Return the Amount Paid to Drill and Complete It....................................................................2 Risk of Nonproductive Wells in Development Drilling................................................................................................3 Risk of Reduced Partnership Distributions Because of Decrease in the Price of Oil and Gas.........................................................3 Risks Regarding the Partnership's Gas Market Which Could Reduce Partnership Distributions............................................................3 If You Choose to Invest as a General Partner for the Tax Benefits, Then You Have Greater Risk Than a Limited Partner.....................................................................4 Risk That the Managing General Partner Cannot Meet Its Indemnification and Repurchase Obligations Because Its Liquid Net Worth Is Not Guaranteed.......................................................................................4 Risk That the Managing General Partner Will Not Devote the Necessary Time to the Partnership Because Its Management Obligations Are Not Exclusive...........................................................................5 Risks of a Long-Term Investment Because the Units Are Illiquid and Not Readily Transferable............................................................................................5 The Number of Partnership Wells Drilled Depends Upon the Amount of Subscription Proceeds................................................................................................5 Risk Regarding Lack of Information Regarding a Portion of the Wells..................................................................................5 There is a Risk That the Data Regarding Currently Proposed Wells is Incomplete or Incorrect...............................................................5 Risk of Bias Regarding Geological Report Prepared by Managing General Partner....................................................................6 Managing General Partner's Subordination is not a Guarantee of the Return of Any of Your Investment......................................................................................6 Risk That Borrowings by the Managing General Partner Could Reduce Funds Available for Its Subordination Obligation..............................................................6 Compensation and Fees to the Managing General Partner Regardless of Success of the Partnership's Activities................................................................................6 Risk of Circumstances Causing Distributions to Investors to be Reduced or Delayed...................................................................6 Risks Arising From Conflicts of Interest Between Managing General Partner and the Investors..............................................................6 Risks That Presentment Obligation May Not Be Funded and Repurchase Price May Not Reflect Full Value......................................................................................6 Risk Regarding Participation with Third Parties in Drilling Wells.......................................................................................7 Risk of Prepaying Subscription Proceeds to Managing General Partner................................................................................7 Risks Associated with Managing General Partner's Benefit from Development of Partnership Prospects...............................................................................................7 Tax Risks.....................................................................................................7 You May Owe Taxes in Excess of Your Cash Distributions from the Partnership......................................................................7 Your Deduction for Intangible Drilling Costs May Be Limited for Purposes of the Alternative Minimum Tax.................................................................................8 Investment Interest Deductions of Investor General Partners May Be Limited.........................................................................8 Lack of Tax Shelter Registration...........................................................................8 ADDITIONAL INFORMATION............................................................................................8 FORWARD LOOKING STATEMENTS AND ASSOCIATED RISKS..................................................................................................8 INVESTMENT OBJECTIVES.............................................................................................9 ACTIONS TO BE TAKEN BY MANAGING GENERAL PARTNER TO REDUCE RISKS OF ADDITIONAL PAYMENTS BY INVESTOR GENERAL PARTNERS............................................................................10 CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS..............................................................................................11 Source of Funds..............................................................................................11 Use of Proceeds..............................................................................................11 Subsequent Source of Funds and Borrowings....................................................................13 COMPENSATION.....................................................................................................14 Oil and Gas Revenues.........................................................................................14 Lease Costs..................................................................................................14 Drilling Contracts...........................................................................................15 Per Well Charges.............................................................................................15 Gathering Fees...............................................................................................16 Dealer-Manager Fees..........................................................................................17 Other Compensation...........................................................................................17 Estimate of Administrative Costs and Direct Costs to be Borne by the Partnership...........................................................................17 TERMS OF THE OFFERING............................................................................................18 Subscription to the Partnership..............................................................................18 Partnership Closings and Escrow..............................................................................18 Acceptance of Subscriptions..................................................................................19 Drilling Period..............................................................................................19 Suitability Standards........................................................................................20 In General.............................................................................................20 Purchasers of Limited Partner Units....................................................................20 Purchasers of Investor General Partner Units...........................................................20 Fiduciary Accounts and Confirmations...................................................................21 PRIOR ACTIVITIES.................................................................................................22 MANAGEMENT.......................................................................................................29 Managing General Partner and Operator........................................................................29 Organizational Diagram.......................................................................................30 Officers, Directors and Key Personnel........................................................................30 Remuneration.................................................................................................32 Security Ownership of Certain Beneficial Owners..............................................................32 Transactions with Management and Affiliates..................................................................32 PROPOSED ACTIVITIES..............................................................................................33 Overview of Drilling Activities..............................................................................33 Primary Areas of Operations..................................................................................34 The Clinton/Medina Geological Formation In Northwestern Pennsylvania.......................................................................34 Mississippian/Upper Devonian Sandstone Reservoirs, Fayette County, Pennsylvania...........................................................35 Secondary Areas of Operations................................................................................35 Clinton/Medina Geological Formation In Ohio............................................................................................35 Clinton/Medina Geological Formation In New York........................................................................................36 Mississippian Berea Sandstone in Ohio..................................................................36 Devonian Oriskany Sandstone in Ohio....................................................................36 Kentucky and Virginia..................................................................................37 Acquisition of Leases........................................................................................37 Deep Drilling Rights Retained by Managing General Partner...............................................................................38 Interests of Parties.........................................................................................38 Primary Areas ...............................................................................................39 Clinton/Medina Geological Formation In Northwestern Pennsylvania and Mississippian/Upper Devonian Sandstone Reservoirs in Fayette County, Pennsylvania.....................................................39 Secondary Areas..............................................................................................40 Title to Properties..........................................................................................40 Drilling and Completion Activities; Operation of Producing Wells........................................................................................40 Sale of Oil and Gas Production...............................................................................42 ii Policy of Treating All Wells Equally in a Geographic Area................................................................................42 Gathering of the Gas...................................................................................42 Gas Contracts..........................................................................................43 Marketing of Gas Production from Wells in Other Areas of the United States...............................................................45 Crude Oil..............................................................................................45 Insurance....................................................................................................45 Use of Consultants and Subcontractors........................................................................46 Information Regarding Currently Proposed Wells...............................................................47 COMPETITION, MARKETS AND REGULATION..............................................................................96 Competition and Markets......................................................................................96 Crude Oil Regulation.........................................................................................97 Federal Gas Regulation.......................................................................................97 State Regulations............................................................................................98 Environmental Regulation.....................................................................................98 Proposed Regulation..........................................................................................99 PARTICIPATION IN COSTS AND REVENUES..............................................................................99 In General...................................................................................................99 Costs........................................................................................................99 Revenues....................................................................................................100 Subordination of Portion of Managing General Partner's Net Revenue Share..............................................................................101 Table of Participation in Costs and Revenues................................................................101 Allocation and Adjustment Among Investors...................................................................102 Distributions...............................................................................................103 Liquidation.................................................................................................103 CONFLICTS OF INTEREST...........................................................................................103 In General..................................................................................................103 Conflicts Regarding Transactions with the Managing General Partner and its Affiliates....................................................................104 Conflict Regarding the Drilling and Operating Agreement................................................................................................104 Conflicts Regarding Sharing of Costs and Revenues...........................................................104 Conflicts Regarding Tax Matters Partner.....................................................................105 Conflicts Regarding Other Activities of the Managing General Partner, the Operator and Their Affiliates.........................................................................................105 Conflicts Involving the Acquisition of Leases...............................................................105 Conflicts Between Investors and the Managing General Partner as an Investor........................................................................108 Lack of Independent Underwriter and Due Diligence Investigation..................................................................................108 Conflicts Concerning Legal Counsel..........................................................................108 Conflicts Regarding Preparation of Geological Report.....................................................................................108 Conflicts Regarding Presentment Feature.....................................................................108 Conflicts Regarding Managing General Partner Withdrawing an Interest...............................................................................109 Conflicts Regarding Order of Pipeline Construction and Gathering Fees....................................................................................109 Procedures to Reduce Conflicts of Interest..................................................................109 Policy Regarding Roll-Ups...................................................................................110 Certain Transactions........................................................................................111 FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER........................................................................................112 In General..................................................................................................112 Limitations on Managing General Partner Liability as Fiduciary.............................................................................................112 TAX ASPECTS.....................................................................................................113 Summary of Tax Opinion......................................................................................113 Partnership Classification..................................................................................114 Limitations on Passive Activities...........................................................................115 Publicly Traded Partnership Rules.....................................................................115 Conversion from Investor General Partner to Limited Partner...............................................................................115 Taxable Year................................................................................................115 2000 Expenditures...........................................................................................115 Availability of Certain Deductions..........................................................................116 Intangible Drilling Costs...................................................................................116 Drilling Contracts..........................................................................................116 Depletion Allowance.........................................................................................117 Depreciation - Modified Accelerated Cost Recovery System ("MACRS").............................................................................118 Leasehold Costs and Abandonment.............................................................................118 Tax Basis of Investors' Interests...........................................................................118 "At Risk" Limitation for Losses.............................................................................118 Distributions from a Partnership............................................................................119 Sale of the Properties......................................................................................119 Disposition of Partnership Interests........................................................................119 Minimum Tax - Tax Preferences...............................................................................119 Limitations on Deduction of Investment Interest.............................................................120 Allocations.................................................................................................120 Partnership Borrowings......................................................................................121 Partnership Organization and Syndication Fees...............................................................121 Tax Elections...............................................................................................121 Disallowance of Deductions under Section 183 of the Internal Revenue Code.............................................................................121 Termination of a Partnership................................................................................121 Lack of Registration as a Tax Shelter.......................................................................121 Investor Lists........................................................................................122 Tax Returns and Audits......................................................................................122 In General............................................................................................122 Tax Returns...........................................................................................122 Penalties and Interest......................................................................................122 In General............................................................................................122 Penalty for Negligence or Disregard of Rules or Regulations..........................................................................122 Valuation Misstatement Penalty........................................................................122 Substantial Understatement Penalty....................................................................123 IRS Anti-Abuse Rule...................................................................................123 State and Local Taxes.......................................................................................123 Severance and Ad Valorem (Real Estate) Taxes................................................................123 Social Security Benefits and Self-Employment Tax............................................................123 Foreign Partners............................................................................................123 Estate and Gift Taxation....................................................................................124 SUMMARY OF PARTNERSHIP AGREEMENT................................................................................124 Liability of Limited Partners...............................................................................124 Amendments..................................................................................................124 Notice......................................................................................................124 Voting Rights...............................................................................................125 Access to Records...........................................................................................125 Withdrawal of Managing General Partner......................................................................126 SUMMARY OF DRILLING AND OPERATING AGREEMENT ......................................................................................................126 REPORTS TO INVESTORS............................................................................................127 PRESENTMENT FEATURE.............................................................................................128 TRANSFERABILITY OF UNITS........................................................................................129 Restrictions on Transfer Imposed by the Securities and Tax Law ..........................................................................................129 PLAN OF DISTRIBUTION............................................................................................130 Commissions...........................................................................................130 Indemnification.......................................................................................131 SALES MATERIAL..................................................................................................131 LEGAL OPINIONS..................................................................................................132 EXPERTS ......................................................................................................132 LITIGATION......................................................................................................132 FINANCIAL INFORMATION CONCERNING THE MANAGING GENERAL PARTNER AND THE PARTNERSHIP.............................................................................................133
iii Exhibits Exhibit (A) Amended and Restated Certificate and Agreement of Limited Partnership Exhibit (I-A) Managing General Partner Signature Page Exhibit (I-B) Subscription Agreement Exhibit (II) Drilling and Operating Agreement Exhibit (B) Special Suitability Requirements and Disclosures to Investors iv SUMMARY OF THE OFFERING 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. ATLAS AMERICA PUBLIC #9 LTD. The partnership is a Pennsylvania limited partnership. Atlas Resources, Inc., 311 Rouser Road, Moon Township, Pennsylvania 15108, (412) 262-2830, will manage the partnership as managing general partner and supervise the drilling, completing and operating of the wells to be drilled as operator. The partnership will drill development wells primarily in the Appalachian Basin. - A development well means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. The managing general partner anticipates that the majority of the wells will be classified as gas wells although some of the wells may be classified as oil wells. DESCRIPTION OF UNITS You may purchase either: - investor general partner units; or - limited partner units. Regardless of which type of unit you buy, costs, revenues and cash distributions will be allocated between you and the other investors pro rata based upon the amount of your subscription. 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 as an investor general partner, then your share of the partnership's 2000 deduction for intangible drilling costs will not be subject to the passive activity limitations. This means that generally you may deduct approximately 90% of your subscription, $9,000 per unit, in 2000. - 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. - LIABILITY. If you invest as an investor general partner, then you will have unlimited liability regarding partnership activities. This means if: - the insurance proceeds; - the managing general partner's indemnification; and - the partnership assets 1 were not sufficient to satisfy a partnership liability for which you and the other investor general partners were also liable, then the managing general partner would call upon you and the other investor general partners to make additional capital contributions to the partnership from your personal assets to satisfy the liability. You and the other investor general partners do not have an option to refuse to make this additional capital contribution. In addition, you and the other investor general partners 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. LIMITED PARTNER UNITS. - TAX EFFECT. If you invest as a limited partner, then your use of the partnership's deduction for intangible drilling costs generally will be limited to net passive income from "passive" trade or business activities. This generally includes the partnership and other limited partner investments. This means that you will not be able to deduct your share of the partnership's intangible drilling costs in 2000 unless you have passive income from investments other than the partnership. - LIABILITY. If you invest as a limited partner, then you will have limited liability and generally will not be liable for amounts beyond your initial investment and your share of undistributed net profits. 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. SPECIAL RISKS OF THE PARTNERSHIP NO GUARANTEE OF RETURN OF INVESTMENT OR RATE OF RETURN ON INVESTMENT BECAUSE OF SPECULATIVE NATURE OF DRILLING OIL AND GAS WELLS. Oil and gas exploration is an inherently speculative activity. Before the drilling of a well the managing general partner cannot predict with any certainty: - the amount of oil and gas recoverable from the well; or - the time it will take to recover the oil and gas. There is a risk that you will not recover all of your investment or if you do recover your investment that you will not receive a rate of return on your investment which is competitive with other types of investment. You will be able to recover your investment only through the partnership's distributions of the sales proceeds from the production of its oil and gas reserves from productive wells. Oil and gas reserves generally deplete over time until the wells are no longer economical to operate. All of these distributions to you may be considered a return of capital until you have received 100% of your investment. RISK THAT A WELL DOES NOT RETURN THE AMOUNT PAID TO DRILL AND COMPLETE IT. There is a risk that even if a well is completed by the partnership and produces oil and gas in commercial quantities it will not produce enough oil and gas to pay for the costs of drilling and completing the well, even if tax benefits are considered. The managing general partner has formed 34 partnerships since 1985, 29 of which were formed in 1990 or subsequent years. All the partnerships are continuing to make cash distributions, however, 32 of the 34 partnerships have not yet returned to the investor 100% of his capital contributions without taking tax savings into account. 2 RISK OF NONPRODUCTIVE WELLS IN DEVELOPMENT DRILLING. Although drilling development wells reduces the risk of drilling nonproductive wells, there is a risk that the partnership will drill some wells which are nonproductive 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. RISK OF REDUCED PARTNERSHIP DISTRIBUTIONS BECAUSE OF DECREASE IN THE PRICE OF OIL AND GAS. There is no assurance of the price at which the partnership's oil and gas will be sold. If oil and gas prices decrease, then your partnership distributions will decrease accordingly. The price will depend on supply and demand factors largely beyond the control of the partnership. During most of the 1980's and 1990's oil and gas prices have been volatile and there is a risk that oil and gas prices could decrease in the future. There is a further risk that the price of oil and gas may decrease during the first years of production when the wells achieve their greatest level of production. This would have the greatest adverse affect on partnership distributions to you. RISKS REGARDING THE PARTNERSHIP'S GAS MARKET WHICH COULD REDUCE PARTNERSHIP DISTRIBUTIONS. In addition to the risk of decreased oil and gas prices described above, there are risks associated with the marketing of the gas which could result in reduced distributions from the partnership to you and the other investors. These risks are set forth below. - There is a risk that competition from other gas marketers will make it more difficult to market the partnership's gas. - The managing general partner anticipates that a portion of the partnership's gas production will be sold directly to industrial end-users situated in the areas where the wells will be drilled. Selling gas to industrial end-users creates a risk that the partnership may not be paid or may experience delays in receiving payment for natural gas that has already been delivered. For example, after Sharon Steel Corporation filed Chapter 11 bankruptcy in 1987, it continued to purchase most of the managing general partner's and its affiliates' natural gas production in Northwestern Pennsylvania until it filed a second Chapter 11 bankruptcy in 1992 owing monies to the managing general partner and its partnerships. - There can be no assurance that the terms of a gas supply agreement will be favorable over the life of the wells. A substantial portion of the partnership's gas will be sold under a 10-year agreement which provides that the gas price may be adjusted upward or downward in accordance with the spot market price and market conditions. The managing general partner anticipates that the remainder of the partnership's gas will be sold under similar contracts. Thus, there is no assurance of a specific gas price for the term of the agreement, and there is a risk that the price for the partnership's gas will decrease because of market conditions. Furthermore, even if the gas supply contract did not provide for price and other adjustments, in the past low gas prices or other difficulties in marketing gas have resulted in some purchasers renegotiating existing agreements to reduce the contract price for gas and the amount of gas to be purchased. - Partnership revenues may be less the farther the gas is transported because of increased transportation costs. - There is a risk that gas production from the wells may be reduced due to seasonal marketing demands since the demand for gas is usually greater in the winter months because of residential heating requirements than the summer months. There is also a risk that from time to time the managing general partner will reduce production awaiting a better gas price. This would reduce or delay distributions from the partnership to you and the other investors. - Production from wells drilled in certain areas may be delayed for up to several months until construction of the necessary pipelines and production facilities is completed. 3 IF YOU CHOOSE TO INVEST AS A GENERAL PARTNER FOR THE TAX BENEFITS, THEN YOU HAVE GREATER RISK THAN A LIMITED PARTNER. If you invest as an investor general partner for the tax benefits instead of as a limited partner, then under Pennsylvania law you will have unlimited liability for the partnership's activities. 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 of the 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 the partnership's obligations and liabilities. Also, the partnership may own less than 100% of the interest in some of the wells. If a court holds you and the other third party owners of the well to be liable for the development and operation of a well and the third party well owner does not pay its proportionate share of the costs and liabilities associated with the well, then the partnership and you and the other investor general partners would be liable to third parties for those costs and liabilities. The partnership will have the benefit of general and excess liability insurance of $50 million during drilling operations and $11 million thereafter, per occurrence and in the aggregate. Nevertheless, 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 damages 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 which result in property damage or personal injury or death to third parties in excess of the amounts insured under the policies. The drilling hazards include, but are not limited to: - well blowouts; - fires; and - explosions. If the insurance proceeds, partnership assets, and the managing general partner's indemnification of you and the other investor general partners were not sufficient to satisfy the liability, then your personal assets could be required to be used to satisfy the liability. If this occurs, then you will not have an option to refuse to contribute the additional funds called for by the managing general partner to pay partnership liabilities. RISK THAT THE MANAGING GENERAL PARTNER CANNOT MEET ITS INDEMNIFICATION AND REPURCHASE OBLIGATIONS BECAUSE ITS LIQUID NET WORTH IS NOT GUARANTEED. The managing general partner has made commitments to you and the other investors regarding the following: - the payment of equipment costs and organization costs; - indemnification of the investor general partners for liabilities in excess of their pro rata share of partnership assets; and - repurchasing the units. A significant financial reversal for the managing general partner could adversely affect its ability to honor these obligations. This would reduce the value of the units. 4 The net worth of the managing general partner is based primarily on the estimated value of its producing gas properties and is not available in cash without borrowings or a sale of the properties. Also, if gas prices decrease, then the estimated value of the properties and the net worth of the managing general partner will be reduced. There is no assurance that the managing general partner will have the necessary net worth, 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 and will make similar financial commitments in other partnerships. RISK THAT THE MANAGING GENERAL PARTNER WILL NOT DEVOTE THE NECESSARY TIME TO THE PARTNERSHIP BECAUSE ITS MANAGEMENT OBLIGATIONS ARE NOT EXCLUSIVE. The managing general partner must devote the amount of time to the partnership's affairs that it determines is reasonably necessary. However, the managing general partner and its affiliates will be engaged in other oil and gas activities and unrelated business ventures for their own account or for the account of others during the term of the partnership, including other partnerships. Thus, there is a risk that the managing general partner will not devote the necessary time to the partnership. RISKS OF A LONG-TERM INVESTMENT 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 partnership agreement and the state and federal securities laws. The units cannot be readily liquidated, and there is no market for the sale of the units. Also, a sale of your units could create adverse tax and economic consequences for you. THE NUMBER OF PARTNERSHIP WELLS DRILLED DEPENDS UPON THE AMOUNT OF SUBSCRIPTION PROCEEDS. If all of the units offered are not sold, then fewer wells will be drilled which decreases the partnership's ability to spread the risks of drilling. The managing general partner anticipates that approximately 5.5 wells will be drilled if the minimum required subscriptions of $1 million are received, and approximately 80 wells will be drilled if subscriptions for $15 million are received. Also, there is a risk of 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 which would shift the risk of loss to the managing general partner as drilling contractor. If there are cost overruns on a well or wells, then the managing general partner anticipates that it would use subscription proceeds, if available, to pay the cost overrun, or advance the necessary funds to the partnership. However, using subscription proceeds to pay cost overruns will result in the partnership drilling fewer wells and having less diversification. On the other hand, to the extent more than the minimum subscriptions are received 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. Also, in a large partnership greater demands will be placed on the management capabilities of the managing general partner. RISK REGARDING LACK OF INFORMATION REGARDING A PORTION OF THE WELLS. The wells currently proposed to be drilled represent approximately 63% of the wells that will be drilled if all the units are sold. Also, the managing general partner has reserved the right to substitute wells and to drill in other areas. Thus, not all of the wells are specified and you do not have any geological, economic, or other information to evaluate any additional and/or substituted wells. Instead, you must rely entirely on the managing general partner to select those wells. Also, the partnership does not have the right of first refusal in the selection of well locations from the inventory of the managing general partner and its affiliates, and they may sell their well locations to other partnerships, companies, joint ventures or other persons at any time. THERE IS A RISK THAT THE DATA REGARDING CURRENTLY PROPOSED WELLS IS INCOMPLETE OR INCORRECT. The information in this prospectus regarding the wells currently proposed to be drilled has been prepared by the managing general partner from sources which it believes are reliable. However, there is a risk that the data does not show: - all the wells drilled in the area; or - the correct volume of gas produced from the wells. 5 Also, the production information for some of the wells is incomplete because: - the information is unavailable to the managing general partner since there is a third-party operator; or - if the managing general partner is the operator the wells have been producing for only a short period of time, or are not yet completed or on-line. RISK OF BIAS REGARDING GEOLOGICAL REPORT PREPARED BY MANAGING GENERAL PARTNER. The geological report for the currently proposed wells in Fayette County, Pennsylvania was prepared by the managing general partner which is not independent. This lack of independence in the preparation of the report may affect its reliability since the managing general partner has an incentive to prepare a more positive report than an independent geologist. MANAGING GENERAL PARTNER'S SUBORDINATION IS NOT A GUARANTEE OF THE RETURN OF ANY OF YOUR INVESTMENT. If your cash distributions are less than a 10% return for each of the first five 12-month periods of partnership 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 a small oil and gas volume, and/or oil and gas prices decrease, then even with subordination your cash flow may be very small and you may not receive a return of your investment. RISK THAT BORROWINGS BY THE MANAGING GENERAL PARTNER COULD REDUCE FUNDS AVAILABLE FOR ITS SUBORDINATION OBLIGATION. The managing general partner anticipates that it will pledge either its partnership interest and/or an undivided interest in the assets of the partnership to secure borrowings for its own corporate purposes. There is a risk that if there was a default to the lender under this pledge arrangement, then this would reduce 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. COMPENSATION AND FEES TO THE MANAGING GENERAL PARTNER REGARDLESS OF SUCCESS OF THE PARTNERSHIP'S ACTIVITIES. The managing general partner and its affiliates will profit from the partnership even if partnership activities result in little or no profit, or a loss to you. RISK OF CIRCUMSTANCES CAUSING DISTRIBUTIONS TO INVESTORS TO BE REDUCED OR DELAYED. There is a risk that you will not receive cash distributions every quarter. Although the managing general partner intends to distribute the cash quarterly, distributions may be deferred to the extent partnership revenues are used for any of the following: - repayment of borrowings: - costs related to completing some of the wells in additional zones; - remedial work to improve a well's producing capability; - 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. RISKS ARISING FROM CONFLICTS OF INTEREST BETWEEN MANAGING GENERAL PARTNER AND THE INVESTORS. There are conflicts of interest between you and the managing general partner and its affiliates. Other than certain guidelines set forth in "Conflicts of Interest," the managing general partner has no established procedures to resolve a conflict of interest. RISKS THAT PRESENTMENT OBLIGATION MAY NOT BE FUNDED AND REPURCHASE PRICE MAY NOT REFLECT FULL VALUE. Subject to certain conditions, beginning in 2005 you may present your units to the managing general partner for purchase. There is a risk that the managing general partner will determine, in its sole discretion, that it does not have the necessary cash flow or cannot arrange financing for this purpose on reasonable terms. In either event the managing general partner is able to suspend the 6 presentment feature. This risk is further increased because the managing general partner has and will incur similar presentment obligations in connection with other partnerships. There is a risk that the presentment price may not reflect the full value of the partnership's property or your units because of the difficulty in accurately estimating oil and gas reserves. The estimates are merely appraisals of value and may not correspond to realizable value. Also, there can be no assurance that the presentment price paid for your units and any distributions received by you before the presentment will be equal to the purchase price of the units. You might realize a greater return if you retain the units, which you may elect, rather than selling the units to the managing general partner. RISK REGARDING PARTICIPATION WITH THIRD PARTIES IN DRILLING WELLS. The managing general partner anticipates that the partnership will own 25% to 100% of the interest in its wells subject to royalties and any other burdens on the leases. Thus, third parties may participate with the partnership in drilling some of the wells. Additional financial risks exist when the cost 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, then the partnership would have to pay the costs of the defaulting party. If the managing general partner were not the actual operator of the well, then there is a risk that the managing general partner cannot supervise the third-party operator closely enough. Decisions concerning expenditures related to the well and how the well is operated will be made by a third-party operator and may not be in the best interests of the partnership. There is also a risk that a third-party operator will have financial difficulties and fail to pay for materials or services on the wells it drills or operates and, in that event, the partnership could incur extra costs in discharging materialmen's and workmen's liens. The managing general partner may not be the operator of the well if the partnership owns less than a 50% interest in the well or if the well location is originated by a third-party and as a part of the terms of acquisition it requires that it be named operator. RISK OF PREPAYING SUBSCRIPTION PROCEEDS TO MANAGING GENERAL PARTNER. Under the drilling and operating agreement the partnership will be required to immediately pay the managing general partner the investors' share of the entire contract price for drilling and completing the partnership's wells. Thus, these funds could be subject to claims of the managing general partner's creditors. RISKS ASSOCIATED WITH MANAGING GENERAL PARTNER'S BENEFIT FROM DEVELOPMENT OF PARTNERSHIP PROSPECTS. A risk is created by the right of the managing general partner's parent company, Atlas America, and its affiliate Atlas Pipeline Partners, L.P., to determine the order of priority for constructing gathering lines which may be required to connect certain of the partnership's wells into the gathering system of Atlas Pipeline Partners. Also, the managing general partner may choose well locations along the gathering system which would benefit its parent company and Atlas Pipeline Partners, even if there are well locations available in the area or other areas which offer the partnership a greater potential return. TAX RISKS YOU MAY OWE TAXES IN EXCESS OF YOUR CASH DISTRIBUTIONS FROM THE PARTNERSHIP. There is a risk that you may become subject to income tax liability in excess of cash actually received from the partnership. For example: - if the partnership borrows money your share of partnership revenues used to pay principal on the loan will be included in your taxable income from the partnership and will not be deductible; - taxable income or gain may be allocated to you if there is a deficit in your capital account even though you do not receive a corresponding distribution of partnership revenues; - partnership revenues may be retained by the managing general partner for partnership costs or to establish a reserve for future estimated costs, including a reserve for the estimated costs of eventually plugging and abandoning the wells; and - the taxable disposition of partnership property or your units may result in income tax liability in excess of cash distributions. 7 YOUR DEDUCTION FOR INTANGIBLE DRILLING COSTS MAY BE LIMITED FOR PURPOSES OF THE ALTERNATIVE MINIMUM TAX. You will be allocated a share of the partnership's deduction for intangible drilling costs. However, alternative minimum taxable income of most investors cannot be reduced by more than 40% by the deduction for intangible drilling costs. INVESTMENT INTEREST DEDUCTIONS OF INVESTOR GENERAL PARTNERS MAY BE LIMITED. An investor general partner's share of the partnership's deduction for intangible drilling costs will reduce his investment income and may adversely affect the deductibility of his investment interest expense, if any. LACK OF TAX SHELTER REGISTRATION. The managing general partner believes that the partnership is not a tax shelter required to register with the IRS. If it is subsequently determined by the IRS or the courts that the partnership was required to be registered with the IRS as a tax shelter, then you would be liable for a $250 penalty for failure to include a tax registration number of the partnership on your tax return, unless this failure was due to reasonable cause. ADDITIONAL INFORMATION The partnership currently is not required to file reports with the SEC. However, a registration statement on Form SB-2 has been filed on behalf of the partnership with the SEC. Certain portions of the registration statement have been deleted from this prospectus under SEC rules and regulations. Also, statements in this prospectus concerning the contents of any document are incomplete. You are urged to refer to the registration statement and exhibits for further information including the provisions of any document referred to in this prospectus. You may read and copy any materials filed as a part of the registration statement, including the tax opinion as set forth on Exhibit 8, at the SEC's Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. 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 partnership. The address of that site is http://www.sec.gov. Also, you may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, 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. These forward-looking statements include such things as: - investment objectives; - business strategy; - estimated future capital expenditures; - competitive strengths and goals; - references to future success; 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. 8 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, including: - general economic market or business conditions; - changes in laws or regulations; - 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; - uncertainties concerning the price of gas; and - other risks. 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 the subscription proceeds in natural gas development wells which will: - Provide quarterly cash distributions to you until the wells are depleted, historically 20+ years, with a preferred annual cash flow of 10% during the first five years based on your original subscription amount. A reserve and economic report effective September, 1999 which was prepared by Wright & Company, Inc., petroleum consultants, and reviewed by the managing general partner, evaluated the past history and estimated future production of 1,016 wells drilled to the Clinton/Medina geological formation which is the objective formation in the partnership's primary drilling area in Northwestern Pennsylvania, as well as its secondary areas in New York and certain areas in Ohio. Based on data in that report, approximately 907 of those wells are expected by the managing general partner to produce more than 20 years. - Obtain tax deductions in 2000 from intangible drilling costs to offset a portion of your taxable income, subject to the passive activity rules if you invest as a limited partner. One unit will produce a 2000 tax deduction of approximately $9,000, 90%: - against ordinary income if you invest as an investor general partner; and - against passive income if you invest as a limited partner. If you are in either the 39.6% or 36% tax bracket, then one unit will save you approximately $3,564 or $3,240 respectively in federal taxes this year. Most states also allow this type of a deduction against the state income tax. - Offset a portion of any taxable income generated by the partnership with tax deductions from percentage depletion, which is 24% in 2000 and is estimated to be 26% on net revenue. The managing general partner estimates that in 2000 this feature would reduce your effective tax rate from 39.6% to 29.3%, which is 74% of 39.6%, on partnership net revenues. The percentage depletion rate fluctuates from year to year depending on the price of oil, but will not be less than the statutory rate of 15% nor more than 25%. 9 ATTAINMENT OF THE PARTNERSHIP'S INVESTMENT OBJECTIVES WILL DEPEND ON MANY FACTORS, INCLUDING THE ABILITY OF THE MANAGING GENERAL PARTNER TO SELECT SUITABLE WELLS WHICH WILL BE PRODUCTIVE AND PRODUCE ENOUGH REVENUE TO RETURN THE INVESTMENT MADE. THE SUCCESS OF THE PARTNERSHIP DEPENDS LARGELY ON FUTURE ECONOMIC CONDITIONS, ESPECIALLY THE FUTURE PRICE OF OIL AND GAS WHICH IS VOLATILE AND MAY DECREASE. 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 as an investor general partner so that you can receive an immediate tax deduction 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 partnership will have $50 million dollars of liability coverage during drilling operations and $11 million dollars after drilling operations cease. - CONVERSION OF INVESTOR GENERAL PARTNER UNITS TO LIMITED PARTNER INTERESTS. Your investor general partner units will be automatically converted by the managing general partner to limited partner interests after substantially all of the partnership wells have been drilled and completed. The managing general partner anticipates conversion in late summer of 2001. After conversion you will have the lesser liability of a limited partner under Pennsylvania 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. Thus, you might become liable for partnership obligations in excess of your subscription 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 conversion. - NONRECOURSE DEBT. The partnership will be permitted to borrow funds only from the managing general partner or its affiliates without recourse against your non-partnership assets. Thus, if there is a default under this loan arrangement you cannot be required to contribute funds to the partnership. Any borrowings will be repaid from partnership revenues. The amount that may be borrowed at any one time may not exceed an amount equal to 5% of the investors' subscriptions. 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 shares of partnership losses. To further protect you, during producing operations all third party goods and services will be acquired by the managing general partner and its affiliates, and the partnership will then acquire the goods and services from the managing general partner and its affiliates at their cost. - INDEMNIFICATION. The managing general partner will indemnify you from any liability incurred in connection with the partnership which is in excess of: - your interest in the undistributed net assets of the partnership; and - insurance proceeds, if any. 10 The managing general partner's indemnification obligation, however, will not eliminate your potential liability if the insurance is not sufficient or available to cover a liability and 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. CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS SOURCE OF FUNDS Upon completion of the offering the partnership's source of funds will be as follows: - the capital contributions of you and the other investors will range from $1 million if 100 units are sold to $15 million if 1,500 units are sold; and - the capital contributions of the managing general partner will range from approximately $345,000 if 100 units are sold, to approximately $4,950,000 if 1,500 units are sold. The total amount of capital contributions available to the partnership from both the managing general partner and you and the other investors will range from approximately $1,345,000 if 100 units are sold to approximately $19,950,000 if 1,500 units are sold. USE OF PROCEEDS The subscription proceeds received from you and the other investors will be used to pay: - all of the intangible drilling costs of drilling and completing the partnership's wells; and - all of the dealer-manager fee, sales commissions, and reimbursement of bona fide accountable due diligence expenses. The managing general partner will: - pay all of the equipment costs, organization costs, and the reimbursement of marketing expenses to the dealer-manager; and - contribute all of the leases to the partnership covering the acreage on which the wells will be drilled. 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. Substantially all of the proceeds available to the partnership will be expended for the following purposes and in the following manner: 11 INVESTOR CAPITAL
ENTITY RECEIVING 100 UNITS 1,500 UNITS PAYMENT NATURE OF PAYMENT SOLD % (1) SOLD % (1) ------- ----------------- ---- ----- ---- ----- TOTAL INVESTOR CAPITAL $1,000,000 100% $15,000,000 100% LESS: ORGANIZATION AND OFFERING EXPENSES Broker-Dealers Dealer-manager fee, sales $100,000 10% $1,500,000 10% commissions, and reimbursement for bona fide accountable due diligence expenses Various Organization costs -0- -0- -0- -0- AMOUNT AVAILABLE FOR INVESTMENT: Managing General Partner Intangible drilling costs $900,000 90% $13,500,000 90% Managing General Partner Equipment costs -0- -0- -0- -0- Managing General Partner Leases -0- -0- -0- -0-
-------------------------------- (1) The percentage is based upon total investor subscriptions and excludes the managing general partner's capital contribution. MANAGING GENERAL PARTNER CAPITAL
ENTITY RECEIVING 100 UNITS 1,500 UNITS PAYMENT NATURE OF PAYMENT SOLD % (1) SOLD % (1) ------- ----------------- ---- ----- ---- ----- TOTAL MANAGING GENERAL PARTNER CAPITAL $345,000 100% $4,950,000 100% LESS: ORGANIZATION AND OFFERING EXPENSES Broker-Dealers Dealer-manager fee, sales -0- -0- -0- -0- commissions, and reimbursement for bona fide accountable due diligence expenses Broker-Dealers Reimbursement of marketing $5,000 1.5% $75,000 1.4% expenses Various Organization costs $45,000 13.0% $675,000 12.7% AMOUNT AVAILABLE FOR INVESTMENT: Managing General Partner Intangible drilling costs -0- -0- -0- -0- Managing General Partner Equipment costs $295,000 85.5% $4,200,000(2) 85.9% Managing General Partner Leases (3) (3) (3) (3)
----------------------------------- (1) The percentage is based upon the managing general partner's capital contribution and excludes the investors' subscriptions. (2) On average over all of the wells drilled and completed by the partnership the managing general partner anticipates that the average equipment cost per well will be $52,500. (3) Instead of contributing cash for the leases, the managing general partner will assign the leases to the partnership. On average over all of the wells to be drilled by the partnership, the managing general partner anticipates that the average lease cost per prospect will be $3,232. 12 SUBSEQUENT SOURCE OF FUNDS AND BORROWINGS The managing general partner anticipates that substantially all the partnership's initial capital will be committed or expended after the offering. If the partnership requires additional funds for cost overruns, completing some of the wells in a third zone, or additional development or remedial work is required for a well after it begins producing, then these funds may be provided by: - subscription proceeds, if available; - 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 investors' subscriptions and must be without recourse to you and the other investors. 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. Currently, the managing general partner, together with affiliates Resource Energy, Inc. and Viking Resources Corporation, participate in a $40 million revolving credit facility with a group of banks with PNC Bank as the agent bank. A portion of the credit facility, $6.3 million, supports an irrevocable letter of credit in favor of Atlas Pipeline Partners, L.P., in connection with a distribution support agreement between Atlas Pipeline Partners and its general partner. The letter of credit will reduce each quarter as the distribution support obligation reduces. Borrowings under the facility are collateralized by substantially all the oil and gas properties of the borrowers. The current revolving credit facility has a term ending in June 2003. The revolving credit facility contains certain financial covenants of the borrowers, including maintaining the following: - a current ratio, as defined, that exceeds .85 to 1; - a ratio of earnings to fixed charges of 1.5 to 1, increasing to 2.5 to 1 in 2002; - a leverage ratio, essentially a ratio of debt to earnings before interest, taxes and depreciation, of not more than 3 to 1; and - a covenant to preserve the borrowers' tangible net worth, as defined. The credit facility also imposes the following limits on the borrowers: - the borrowers' exploration expense can be no more than 20% of their capital expenditures plus exploration expense, without PNC Bank's consent; 13 - sales, leases or transfers of unsecured property by the borrowers are limited to $1 million without PNC Bank's consent; and - the borrowers cannot incur debt in excess of $2 million to lenders other than the lender under the facility without PNC Bank's consent. As of June 30, 2000, there was $33.0 million of outstanding borrowings under the revolving credit facility. COMPENSATION The items of compensation paid to the managing general partner and its affiliates from the partnership are set forth below. OIL AND GAS REVENUES Until you receive cash distributions and tax benefits equal to 100% of your subscription, you and the other investors and the managing general partner will share in partnership revenues in the same percentages as your respective capital contributions bear to the total partnership capital contributions. After net of tax savings payout the managing general partner will receive an additional 6.5% of partnership revenues, and after partnership payout the managing general partner will receive an additional 8.5% of partnership revenues for a total additional amount of 15% of partnership revenues. LEASE COSTS Under the partnership agreement the managing general partner will contribute to the partnership all the undeveloped leases necessary to drill the partnership's wells. The managing general partner will receive a credit to its capital account equal to: - the cost of the leases; or - fair market value if the managing general partner has reason to believe that cost is materially more than the fair market value of the leases. The cost of the leases will include a portion of the managing general partner's reasonable, necessary and actual expenses for the following: - geological, geophysical and engineering expenses; - interest expense; - legal expense; and - expenses for other like services allocated to the partnership's leases determined using industry guidelines. In Northwestern Pennsylvania and Fayette County, Pennsylvania, which is the partnership's primary area of interest, the managing general partner's lease cost is approximately $3,232 per prospect. Assuming all the leases are situated in this area and the partnership acquires 100% of the interest, the managing general partner estimates that its credit for lease costs will be: - $17,776 if $1,000,000 is received, which is 5.5 wells at $3,232 per prospect; and - $258,560 if $15,000,000 is received, which is 80 wells at $3,232 per prospect. 14 The development of wells on the acreage may also provide the managing general partner with offset drill 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. DRILLING CONTRACTS The partnership will enter into the drilling and operating agreement with the managing general partner to drill and complete the partnership wells at cost plus 15%. If this rate exceeds competitive rates available from other 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. 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. However, the managing general partner may not benefit by interpositioning itself between the partnership and the actual provider of drilling contractor services. Cost when used with respect to services, generally means the reasonable, necessary and actual expense incurred in providing the services, determined in accordance with generally accepted accounting principles. The cost of the well includes all ordinary costs of drilling, testing and completing the well such as: - the cost of a second completion and frac which means, in general, treating a second potentially productive geological formation in an attempt to enhance the gas production from the well; - the cost of installing gathering lines of up to 2,500 feet; and - other necessary facilities for the production of natural gas. The amount of compensation which the managing general partner could earn as a result of these arrangements depends on many factors, including the number of wells drilled. The managing general partner anticipates that on average over all of the wells drilled and completed by the partnership that the average well cost, excluding lease costs, will be $219,390. To the extent that the partnership acquires less than a 100% interest in a well, its drilling and completion costs of that well will be proportionately decreased. On a per well basis the managing general partner will have reimbursement of general and administrative overhead of approximately $12,900 per well and a profit of 15% (approximately $21,850) per well with respect to the intangible drilling costs paid by you and the other investors. Assuming the partnership acquires 100% of the interest in the wells, the managing general partner estimates that its general and administrative overhead reimbursement and profit will be: - $191,125 if $1 million is received, which is 5.5 wells at $34,750 profit and overhead per well; and - $2,780,000 if $15 million is received, which is 80 wells at $34,750 profit and overhead per well. PER WELL CHARGES Under the drilling and operating agreement when the wells begin producing the managing general partner, as operator of the wells, will receive the following: - reimbursement at actual cost for all direct expenses incurred on behalf of the partnership; and - well supervision fees for operating and maintaining the wells during producing operations at a competitive rate. Currently the competitive rates for the areas range from $275 per well per month to $400 per well per month. The well supervision fees will be proportionately reduced to the extent the partnership acquires less than 100% of the interest in the well, and may be adjusted for inflation annually beginning January 1, 2002. If the foregoing rates exceed competitive rates available from other non-affiliated persons in the area engaged in the business of providing comparable services or equipment, then the rates will be adjusted to the competitive rate. 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 15 received for operator services be duplicative of any consideration or reimbursement received pursuant to the partnership agreement. The well supervision fee covers all normal and regularly recurring operating expenses for the production, delivery and sale of oil and gas, 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; - brine disposal; and - rebuilding of access roads. These costs will be charged at the invoice cost of the materials purchased, or the third party services performed. Assuming all the wells are drilled and completed in the partnership's primary area of interest and the partnership acquires 100% of the interest in the wells, the managing general partner estimates that it will receive well supervision fees for the partnership's first 12 months of operation of: - $18,150 if $1 million is received, which is 5.5 wells at $275 per well per month; and - $264,000 if $15 million is received, which is 80 wells at $275 per well per month. GATHERING FEES Atlas Pipeline Partners, L.P. is a master limited partnership which has acquired the gathering system owned by the managing general partner's parent company, Atlas America, and its affiliates. The managing general partner anticipates that this entity, of which approximately 53% is owned by Atlas America and its affiliates, will gather and deliver the majority of the natural gas produced by the partnership to either industrial end-users in the area, local distribution companies, or interstate pipeline systems. The partnership will pay a gathering charge at a competitive rate. Currently the managing general partner anticipates that the partnership will pay the following gathering fees to Atlas Pipeline Partners in its primary and secondary areas:
AREA GATHERING FEE ---- ------------- Clinton/Medina Geological Formation in Pennsylvania, Ohio and New York..........................................................$.29 per mcf (1) Mississippian/Upper Devonian Sandstone Reservoirs in Fayette County, Pennsylvania...............................................$.35 per mcf (1) Mississippian Berea Sandstone Geological Formation in Columbiana County, Ohio....................................................$.35 per mcf (1) Devonian Oriskany Sandstone Geological Formation in Tuscarawas County, Ohio....................................................$.35 per mcf (1) Big Lime, Weir, and Devonian Shale Geological Formation in Kentucky and Virginia................................................................(2) ----------------------------
16 (1) The managing general partner and its affiliates will pay the difference between the amounts set forth above and the greater of $.35 per mcf or 16% of the gross sales price for gas produced to Atlas Pipeline Partners. This arrangement is described in "Proposed Activities - Sale of Oil and Gas Production - Gathering of the Gas." (2) The partnership will use a third-party gathering system. The actual amount to be paid to Atlas Pipeline Partners cannot be quantified because the amount of gas that will be produced from the wells and transported by Atlas Pipeline Partners cannot be predicted. DEALER-MANAGER FEES 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, a .5% reimbursement of marketing expenses, and a .5% reimbursement of the selling agents' bona fide accountable due diligence expenses. The dealer-manager will receive: - $105,000 if $1 million is received; and - $1,575,000 if $15 million is received. All or a portion of the sales commissions, reimbursement of marketing expenses, and reimbursement of the selling agents' bona fide accountable due diligence expenses will be reallowed to the selling agents. The 2.5% dealer-manager fee generally will be reallowed to the wholesalers who are associated with Anthem Securities for subscriptions obtained through the wholesalers' effort. OTHER COMPENSATION The managing general partner or an affiliate will be reimbursed by the partnership for any loan it or an affiliate may make to or on behalf of the partnership and will have the right to charge a competitive rate of interest on any loan. If the managing general partner provides equipment, supplies and other services to the partnership, then it may do so at competitive industry rates. ESTIMATE OF ADMINISTRATIVE COSTS AND DIRECT COSTS TO BE BORNE BY THE PARTNERSHIP The managing general partner and its affiliates will receive an unaccountable, fixed payment reimbursement for their administrative costs which has been determined by the managing general partner to be $75 per well per month. This fee will be proportionately reduced to the extent the partnership acquires less than 100% of the interest in the well, and will not be received for plugged and abandoned wells. The managing general partner estimates that the unaccountable, fixed payment reimbursement for administrative costs allocable to the partnership's first 12 months of operation will not exceed approximately: - $4,950 if $1 million is received, which is 5.5 wells at $75 per well per month; and - $72,000 if $15 million is received, which is 80 wells at $75 per well per month. 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 may vary from the estimates shown for numerous reasons which cannot accurately be predicted. These reasons include: - the number of investors; - the number of wells drilled; - the partnership's degree of success in its activities; - the extent of any production problems; 17 - inflation; and - various other factors involving the administration of the partnership.
Minimum Maximum Subscriptions Subscriptions ($1,000,000) ($15,000,000) ------------ ------------- DIRECT COSTS External Legal....................................... $ 6,000 $ 6,000 Accounting Fees...................................... 2,500 6,000 Independent Engineering Reports...................... 1,500 3,000 ------ ------ TOTAL ............................................... $10,000 $15,000 ======= =======
TERMS OF THE OFFERING SUBSCRIPTION TO THE PARTNERSHIP The partnership will offer a minimum of 100 units, which is $1 million, and a maximum of 1,500 units, which is $15 million. Units in the partnership are offered at a subscription price of $10,000 per unit. Your minimum subscription is one unit; however, the managing general partner, in its discretion, may accept one-half unit ($5,000) subscriptions from you at any time. Larger subscriptions will be accepted in $1,000 increments. You must pay your subscription 100% in cash at the time of subscribing. The managing general partner will have exclusive management authority for the partnership. You will have the election to purchase units as either an investor general partner or a limited partner. PARTNERSHIP CLOSINGS AND ESCROW The offering period will begin on the date of this prospectus, and will end on or before December 31, 2000, as determined by the managing general partner, in its sole discretion. The offering period will not be extended beyond December 31, 2000, and subject to the receipt of the minimum subscriptions of $1 million, the managing general partner may close the offering period before this date. No subscriptions to the partnership will be accepted after the first to occur: - the receipt of the maximum subscriptions, or - the close of the offering by the managing general partner. If subscriptions for $1 million are not received by the offering termination date, then the sums 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 10% of the units, they do not currently anticipate purchasing any units. If they do buy units, then those units will not be applied towards the minimum subscriptions required for the partnership to begin operations. Subscription proceeds will be held in a separate interest bearing escrow account at National City Bank of Pennsylvania until receipt of the minimum subscriptions. Upon receipt of the minimum subscriptions, the partnership will break escrow. The partnership will begin all activities, including drilling, after breaking escrow, although the managing general partner does not anticipate that there will be any production before the offering closes. After breaking escrow the partnership funds and additional subscription payments will be paid directly to the partnership account and will continue to earn interest until the offering closes. 18 You will receive interest on your subscription up until the date the offering closes at the market rate paid by National City Bank of Pennsylvania. The interest will be paid to you approximately eight weeks after the offering closes. Subscription proceeds will be invested during the escrow period only in institutional investments comprised of or secured by securities of the United States government. The funds in the partnership account, before their use for partnership operations, 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 an investment company under the Investment Company Act of 1940, then the investment activity will cease. Subscriptions will not be commingled with the funds of the managing general partner or its affiliates nor will subscriptions be subject to the claims of their creditors. ACCEPTANCE OF SUBSCRIPTIONS Your execution of your subscription agreement constitutes your offer to buy units and to hold the offer open until either: - your subscription is accepted or rejected by the managing general partner; or - you withdraw your offer. If you elect to withdraw your offer before it is accepted by the managing general partner, then you must give written notice to the managing general partner. Your subscription will be accepted or rejected by the partnership within 30 days of its receipt. Acceptance of subscriptions is discretionary with the managing general partner and it may reject your subscription for any reason without incurring any liability to you for this decision. If your subscription is rejected, then all funds will be promptly returned to you. You will be admitted to the partnership as follows: - 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' funds to the partnership; and - if your subscription is accepted 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: - the execution of the partnership agreement and your agreement to be bound by its terms as a partner; and - your grant of a special power of attorney to the managing general partner to file amended certificates of limited partnership, governmental reports and certifications, and other matters. DRILLING PERIOD Although the managing general partner anticipates that the partnership will spend the entire subscription proceeds soon after the offering closes, the partnership will have 12 months to use or commit funds to drilling activities. If, within the 12-month period, the partnership has not used, or committed for use, the net subscription proceeds, then the managing general partner will cause the remainder of the net subscription proceeds to be distributed pro rata to you and the other investors as a return of capital. The managing general partner will also reimburse you and the other investors for selling or other offering expenses allocable to the return of capital. 19 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. This suitability determination will be based on your investment objectives and financial situation, regardless of your income or net worth. Because the partnership's income would be unrelated business taxable income, subscriptions will not be accepted from IRAs, Keogh plans and qualified retirement plans. The managing general partner will not accept your subscription until it has reviewed your apparent qualifications. 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 maintain during the partnership's term and for at least six years thereafter a record of your suitability. Units will be sold to you only if you have: - a minimum net worth of $225,000; or - a minimum net worth of $60,000 and had during the last tax year or estimate that you will have during the current tax year "taxable income" as defined in Section 63 of the Internal Revenue Code of at least $60,000 without regard to an investment in the partnership. Net worth will be determined exclusive of home, home furnishings and automobiles. However, if you are a resident of the states set forth below, then additional suitability requirements are applicable to you. PURCHASERS OF LIMITED PARTNER UNITS. If you are a resident of California and you purchase limited partner units, then you must: - have a net worth of not less than $250,000, exclusive of home, furnishings, and automobiles, and expect to have gross income in the current tax year of $65,000 or more; or - have a net worth of not less than $500,000, exclusive of home, furnishings, and automobiles; or - have a net worth of not less than $1,000,000; or - expect to have gross income in the current tax year of not less than $200,000. If you are a resident of Michigan or North Carolina and you purchase limited partner units, then you must: - have a net worth of not less than $225,000, exclusive of home, furnishings, and automobiles; or - have a net worth of not less than $60,000, exclusive of home, furnishings, and automobiles, and estimated current tax year taxable income as defined in Section 63 of the Internal Revenue Code of $60,000 or more without regard to an investment in the partnership. In addition, if you are a resident of Michigan, Ohio or Pennsylvania, then you must not make an investment in the partnership in excess of 10% of your net worth, exclusive of home, furnishings and automobiles. PURCHASERS OF INVESTOR GENERAL PARTNER UNITS. If you are a resident of Alabama, Maine, Massachusetts, Minnesota, North Carolina, Ohio, Pennsylvania, Tennessee or Texas and you purchase investor general partner units, then you must: - have an individual or joint net worth with your spouse of $225,000 or more, without regard to the investment in the partnership, exclusive of home, furnishings, and automobiles, and a combined gross income of $100,000 or more for the current year and for the two previous years; or 20 - have an individual or joint net worth with your spouse in excess of $1,000,000, inclusive of home, home furnishings and automobiles; or - have an individual or joint net worth with your spouse in excess of $500,000, exclusive of home, home furnishings, and automobiles; or - have 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. If you are a resident of Arizona, Indiana, Iowa, Kansas, Kentucky, Michigan, Mississippi, Missouri, New Hampshire, New Mexico, Oklahoma, Oregon, South Dakota, Vermont or Washington and you purchase investor general partner units, then you must: - have an individual or joint net worth with your spouse of $225,000 or more, without regard to the investment in the partnership, exclusive of home, furnishings, and automobiles, and a combined "taxable income" of $60,000 or more for the previous year and expect to have a combined "taxable income" of $60,000 or more for the current year and for the succeeding year; or - have an individual or joint net worth with your spouse in excess of $1,000,000, inclusive of home, home furnishings and automobiles; or - have an individual or joint net worth with your spouse in excess of $500,000, exclusive of home, home furnishings, and automobiles; or - have 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 Michigan, Ohio or Pennsylvania, then you must not make an investment in the partnership in excess of 10% of your net worth, exclusive of home, furnishings and automobiles. If you are a resident of California and you purchase investor general partner units, then you must: - have a net worth of not less than $250,000, exclusive of home, furnishings, and automobiles, and expect to have gross income in the current tax year of $120,000 or more; or - have a net worth of not less than $500,000, exclusive of home, furnishings, and automobiles; or - have a net worth of not less than $1,000,000; or - expect to have gross income in the current tax year of not less than $200,000. FIDUCIARY ACCOUNTS AND CONFIRMATIONS. In the case of a sale to a fiduciary account, all 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. 21 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. Also, the managing general partner may not complete a sale of units to you until at least five business days after the date you receive a final prospectus and will send you a confirmation of purchase. PRIOR ACTIVITIES The following tables, other than Table 5, reflect certain historical data with respect to 26 private drilling partnerships which raised a total of $96,075,134 and 8 public drilling partnerships which raised a total of $60,074,570, which the managing general partner has sponsored. IT SHOULD NOT BE ASSUMED THAT YOU AND THE OTHER INVESTORS 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. 22 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 July 15, 2000
----------------------------------------------------------------------------------------------------------------------------------- Date of Com- Years mence- Date of Wells Number Investor Atlas ment of First In of Subscrip- Invest- Total Opera- Distri- Produc- Previous Partnership Investors tions ment Capital tions butions tion Assessments ----------- --------- ----- ---- ------- ----- ------- ---- ----------- Atlas L.P. #1 - 1985 19 $600,000 $114,800 $714,800 12/31/85 07/02/86 14.55 -0- A.E. Partners 1986 24 631,250 120,400 751,650 12/31/86 04/02/87 13.55 -0- A.E. Partners 1987 17 721,000 158,269 879,269 12/31/87 04/02/88 12.55 -0- A.E. Partners 1988 21 617,050 135,450 752,500 12/31/88 04/02/89 11.55 -0- A.E. Partners 1989 21 550,000 120,731 670,731 12/31/89 04/02/90 10.55 -0- A.E. Partners 1990 27 887,500 244,622 1,132,122 12/31/90 04/02/91 9.55 -0- A.E. Nineties-10 60 2,200,000 484,380 2,684,380 12/31/90 03/31/91 9.33 -0- A.E. Nineties-11 25 750,000 268,003 1,018,003 09/30/91 01/31/92 8.50 -0- A.E. Partners 1991 26 868,750 318,063 1,186,813 12/31/91 04/02/92 8.33 -0- A.E. Nineties-12 87 2,212,500 791,833 3,004,333 12/31/91 04/30/92 8.25 -0- A.E. Nineties-JV 92 155 4,004,813 1,414,917 5,419,730 10/28/92 04/05/93 7.58 -0- A.E. Partners 1992 21 600,000 176,100 776,100 12/14/92 07/02/93 7.08 -0- A.E. Nineties-Public #1 221 2,988,960 528,934 3,517,894 12/31/92 07/15/93 6.83 -0- A.E. Nineties-1993 Ltd. 125 3,753,937 1,264,183 5,018,120 10/08/93 02/10/94 6.50 -0- A.E. Partners 1993 21 700,000 219,600 919,600 12/31/93 07/02/94 6.25 -0- A.E. Nineties-Public #2 269 3,323,920 587,340 3,911,260 12/31/93 06/15/94 6.00 -0- A.E. Nineties-14 263 9,940,045 3,584,027 13,524,072 08/11/94 01/10/95 5.50 -0- A.E. Partners 1994 23 892,500 231,500 1,124,000 12/31/94 07/02/95 5.25 -0- A.E. Nineties-Public #3 391 5,799,750 928,546 6,728,296 12/31/94 06/05/95 5.25 -0- A.E. Nineties-15 244 10,954,715 3,435,936 14,390,651 09/12/95 02/07/96 4.42 -0- A.E. Partners 1995 23 600,000 244,725 844,725 12/31/95 10/02/96 4.00 -0- A.E. Nineties-Public #4 324 6,991,350 1,287,752 8,279,102 12/31/95 07/08/96 4.25 -0- A.E. Nineties-16 274 10,955,465 1,643,320 12,598,785 07/31/96 01/12/97 3.58 -0- A.E. Partners 1996 21 800,000 367,416 1,167,416 12/31/96 07/02/97 3.25 -0- A.E. Nineties-Public #5 378 7,992,240 1,654,740 9,646,980 12/31/96 06/08/97 3.25 -0- A.E. Nineties-17 217 8,813,488 2,113,947 10,927,435 08/29/97 12/12/97 2.67 -0- A.E. Nineties-Public #6 393 9,901,025 1,950,345 11,851,370 12/31/97 06/08/98 2.25 -0- A.E. Partners 1997 13 506,250 231,050 737,300 12/31/97 07/02/98 2.08 -0- A.E. Nineties-18 225 11,391,673 3,448,751 14,840,424 07/31/98 01/07/99 1.58 -0- A.E. Nineties-Public #7 366 11,988,350 3,812,150 15,800,500 12/31/98 07/10/99 1.25 -0- A.E. Partners 1998 26 1,740,000 756,360 2,496,360 12/31/98 07/02/99 1.25 -0- A.E. Nineties-19 288 15,720,450 4,776,598 20,497,048 09/30/99 01/14/00 0.75 -0- A.E. Nineties-Public #8 380 11,088,975 3,148,181 14,237,156 12/31/99 06/09/00 0.25 -0- A.E. Partners 1999 8 450,000 196,500 646,500 12/31/99 - - -0- -----------------------------------------------------------------------------------------------------------------------------------
23 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 PARTNERSHIP. TABLE 2 WELL STATISTICS - DEVELOPMENT WELLS As of July 15, 2000
-------------------------------------------------------------------------------------------------------------------------- GROSS WELLS(1) NET WELLS(2) ------------------------------- ---------------------------------- Partnership Oil Gas Dry (3) Oil Gas Dry (3) ----------- --- --- ------- --- --- ------- Atlas L.P. #1-1985 (4) 0 7 1 0 3.15 0.25 A.E. Partners 1986 0 8 0 0 3.50 0.00 A.E. Partners 1987 0 9 0 0 4.10 0.00 A.E. Partners 1988 0 9 0 0 3.80 0.00 A.E. Partners 1989 0 10 0 0 3.30 0.00 A.E. Partners 1990 0 12 0 0 5.00 0.00 A.E. Nineties-10 0 12 0 0 11.50 0.00 A.E. Nineties-11 0 14 0 0 4.30 0.00 A.E. Partners 1991 0 12 0 0 4.95 0.00 A.E. Nineties-12 0 14 0 0 12.50 0.00 A.E. Nineties-JV 92 0 52 0 0 24.44 0.00 A.E. Partners 1992 0 7 0 0 3.50 0.00 A.E. Nineties-Public #1 0 14 0 0 14.00 0.00 A.E. Nineties-1993 Ltd. (4) 0 20 2 0 19.40 2.00 A.E. Partners 1993 0 8 0 0 4.00 0.00 A.E. Nineties-Public #2 0 16 0 0 15.31 0.00 A.E. Nineties-14 (4) 0 55 1 0 55.00 1.00 A.E. Partners 1994 (4) 0 12 0 0 5.00 0.00 A.E. Nineties-Public #3 0 27 0 0 26.00 0.00 A.E. Nineties-15 (4) 0 61 0 0 55.50 0.00 A.E. Partners 1995 0 6 0 0 3.00 0.00 A.E. Nineties-Public #4 0 31 0 0 30.50 0.00 A.E. Nineties-16 (4) 0 57 0 0 47.50 0.00 A.E. Partners 1996 0 13 0 0 4.84 0.00 A.E. Nineties-Public #5 0 36 0 0 35.91 0.00 A.E. Nineties-17 (4) 0 52 2 0 42.00 1.50 A.E. Nineties-Public #6 0 55 0 0 44.45 0.00 A.E. Partners 1997 0 6 0 0 2.81 0.00 A.E. Nineties-18 0 63 0 0 58.00 0.00 A.E. Nineties-Public #7 0 64 0 0 57.50 0.00 A.E. Partners 1998 0 19 0 0 9.50 0.00 A.E. Nineties-19 (4) 0 86 4 0 79.75 4.00 A.E. Nineties-Public #8 0 58 0 0 54.66 0.00 A.E. Partners 1999 0 5 0 0 2.50 0.00 ------ ----- ------ ------- ------ ----- TOTALS 0 930 10 0 751.17 8.75 ====== ===== ====== ======= ====== ===== --------------------------------------------------------------------------------------------------------------------------
(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 without a completion attempt because the operator has determined that it will not be productive of gas and/or oil in commercial quantities. (4) - Atlas L.P. #1-1985 had 1 gross well (.25 net well) which was completed but non-commercial; - A.E. Nineties-1993 Ltd. had 1 gross well (1 net well) which was completed but non-commercial; - A.E. Nineties-14 had 2 gross wells (2 net wells) which were completed but non-commercial; - A.E. Partners-1994 had 1 gross well (.25 net well) which was completed but non-commercial; - A.E. Nineties-15 had 1 gross well (1 net well) which was completed but non-commercial; - A.E. Nineties-16 had 5 gross wells (4.5 net wells) which were completed but non-commercial; - A.E. Nineties-17 had 3 gross wells (2.5 net wells) which were completed but non-commercial; and - A.E. Nineties-19 had 4 gross wells (4 net wells) which were completed but non-commercial. 24 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 PARTNERSHIP. TABLE 3 INVESTOR OPERATING RESULTS - INCLUDING EXPENSES As of July 15, 2000
------------------------------------------------------------------------------------------------------------------------------------ Cash Total Costs -on- Average Latest Quarterly ------------------------------- Cash Cash Yearly Cash Distribution Partnership Capitalization(1) Operating Admin. Direct Distributions(2) Return Return As of Date of Table ----------- ----------------- --------- ------ ------ ---------------- ------ ------ ------------------- Atlas L.P. #1-1985 $600,000 $158,536 $35,700 $8,335 $1,336,573 223% 15% $7,013 A.E. Partners 1986 631,250 123,163 52,738 7,102 639,925 101% 7% 4,776 A.E. Partners 1987 721,000 120,111 47,247 7,177 515,981 72% 6% 2,536 A.E. Partners 1988 617,050 97,132 43,758 6,691 472,008 76% 7% 2,641 A.E. Partners 1989 550,000 93,099 46,821 5,650 626,356 114% 11% 4,546 A.E. Partners 1990 887,500 133,696 64,166 6,687 809,303 91% 10% 9,235 A.E. Nineties-10 2,200,000 294,008 63,271 22,640 1,430,010 65% 7% 18,599 A.E. Nineties-11 750,000 109,573 68,968 37,777 870,403 116% 14% 12,292 A.E. Partners 1991 868,750 112,168 83,039 14,698 872,413 100% 12% 15,558 A.E. Nineties-12 2,212,500 307,277 66,731 109,481 1,633,629 74% 9% 19,390 A.E. Nineties - JV 92 4,004,813 464,438 102,585 198,344 3,252,883(3) 81% 11% 81,167 A.E. Partners 1992 600,000 65,188 40,275 4,775 607,294 101% 13% 8,989 A.E. Nineties-Public #1 2,988,960 271,789 64,468 82,719 1,784,586 60% 9% 27,095 A.E. Nineties-1993 Ltd. 3,753,937 347,933 70,702 36,279 1,885,912 50% 8% 18,967 A.E. Partners 1993 700,000 76,533 29,738 4,115 685,426 98% 16% 16,410 A.E. Nineties-Public #2 3,323,920 270,178 53,629 37,699 1,577,057 47% 8% 35,652 A.E. Nineties-14 9,940,045 814,378 164,101 41,266 4,404,539 44% 8% 115,150 A.E. Partners 1994 892,500 57,468 32,061 3,438 646,819 72% 14% 21,328 A.E. Nineties-Public #3 5,799,750 380,884 79,637 41,743 2,683,908 46% 9% 76,071 A.E. Nineties-15 10,954,715 692,603 147,045 24,380 4,686,866 43% 10% 174,394 A.E. Partners 1995 600,000 38,827 10,646 2,838 254,307 42% 11% 5,393 A.E. Nineties-Public #4 6,991,350 427,509 84,573 35,912 2,083,878 30% 7% 67,199 A.E. Nineties-16 10,955,465 534,305 96,354 39,601 2,920,939 27% 7% 119,070 A.E. Partners 1996 800,000 44,460 11,833 39,878 232,572 29% 9% 13,219 A.E. Nineties-Public #5 7,992,240 351,079 68,139 22,119 2,125,563 27% 8% 113,595 A.E. Nineties-17 8,813,488 308,559 61,198 97,339 2,189,229 25% 9% 159,172 A.E. Nineties-Public #6 9,901,025 343,140 61,293 14,335 2,230,079 23% 10% 210,591 A.E. Partners 1997 506,250 17,307 4,502 25,965 113,831 22% 11% 10,992 A.E. Nineties-18 11,391,673 307,984 52,576 260,131 1,974,075 17% 11% 248,020 A.E. Nineties-Public #7 11,988,350 248,460 36,669 12,683 1,334,901 11% 9% 218,369 A.E. Partners 1998 1,740,000 45,978 10,044 40,743 332,371 19% 15% 58,008 A.E. Nineties-19 15,720,450 152,887 21,385 4,605 1,083,145 7% 9% 446,670 A.E. Nineties-Public #8 11,088,975 10,671 1,960 0 100,032 1% 4% 100,032 A.E. Partners 1999 450,000 0 0 0 0 0% N/A N/A ------------------------------------------------------------------------------------------------------------------------------------
(1) There have been no partnership borrowings other than from the managing general partner. The approximate principal amounts of such borrowings were as follows: - A.E. Nineties-10 - $330,000; - A.E. Nineties-11 - $112,500; and - A.E. Nineties-12 - $331,875. A portion of each partnership's cash distributions was used to repay that partnership's loan. (2) All cash distributions were from the sale of gas, and not sales of properties. (3) A portion of the cash distributions was used to drill three reinvestment wells at a cost of $333,860 in accordance with the terms of the offering. 25 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 July 15, 2000
------------------------------------------------------------------------------------------------------------------------------------ Cash Total Costs -on- Latest Quarterly ------------------------------- Cash Cash Cash Distribution Partnership Capitalization Operating Admin. Direct Distributions(1) Return As of Date of Table ----------- ----------------- --------- ------ ------ ---------------- ------ ------------------- Atlas L.P. #1-1985 $114,800 $30,197 $6,800 $1,588 $253,135 221% $1,336 A.E. Partners 1986 120,400 23,460 10,045 1,353 122,219 102% 910 A.E. Partners 1987 158,269 34,631 13,623 2,069 131,035 83% 731 A.E. Partners 1988 135,450 31,282 14,092 2,155 117,751 87% 851 A.E. Partners 1989 120,731 20,436 10,278 1,240 143,124 119% 998 A.E. Partners 1990 244,622 44,565 0 0 312,497 128% 3,828 A.E. Nineties-10 484,380 98,003 0 0 505,307 104% 7,300 A.E. Nineties-11 268,003 46,960 29,558 11,132 366,305 137% 5,268 A.E. Partners 1991 318,063 37,389 0 0 377,231 119% 6,244 A.E. Nineties-12 791,833 131,690 28,599 21,413 700,126 88% 8,310 A.E. Nineties-JV 92 1,414,917 228,753 50,527 16,152 846,212 60% 11,337 A.E. Partners 1992 176,100 21,729 0 0 286,202 163% 3,680 A.E. Nineties-Public #1 528,934 85,828 20,358 14,315 495,734 94% 8,556 A.E. Nineties-1993 Ltd. 1,264,183 149,114 30,301 11,966 335,242 27% 8,129 A.E. Partners 1993 219,600 25,511 0 0 252,225 115% 5,987 A.E. Nineties-Public #2 587,340 85,319 16,936 11,905 332,987 57% 11,258 A.E. Nineties-14 3,584,027 401,111 80,826 13,146 1,124,317 31% 1,684 A.E. Partners 1994 231,500 19,156 0 0 228,085 99% 7,786 A.E. Nineties-Public #3 928,546 126,961 26,546 13,914 833,449 90% 25,357 A.E. Nineties-15 3,435,936 296,830 63,019 10,448 1,751,385 51% 2,656 A.E. Partners 1995 244,725 12,942 0 0 75,144 31% 2,223 A.E. Nineties-Public #4 1,287,752 142,503 28,191 11,971 564,423 44% 11,859 A.E. Nineties-16 1,643,320 146,338 26,390 6,040 530,524 32% 16,622 A.E. Partners 1996 367,416 14,820 0 0 94,761 26% 4,919 A.E. Nineties-Public #5 1,654,740 117,026 22,713 7,373 509,021 31% 20,046 A.E. Nineties-17 2,113,947 111,249 22,065 5,750 766,935 36% 27,540 A.E. Nineties-Public #6 1,950,345 114,380 20,431 4,778 731,870 38% 58,707 A.E. Partners 1997 231,050 5,769 0 0 48,099 21% 4,044 A.E. Nineties-18 3,448,751 141,628 24,177 6,751 924,719 27% 114,053 A.E. Nineties-Public #7 3,812,150 111,627 16,474 5,698 305,027 8% 49,898 A.E. Partners 1998 756,360 15,326 0 0 127,719 17% 20,265 A.E. Nineties-19 4,776,598 70,306 9,834 2,118 498,089 10% 205,403 A.E. Nineties-Public #8 3,148,181 4,358 801 0 21,072 1% 21,072 A.E. Partners 1999 196,500 0 0 0 N/A N/A N/A ------------------------------------------------------------------------------------------------------------------------------------
(1) All cash distributions were from the sale of gas and not sales of properties. 26 Table 4 sets forth the aggregate cash distributions and estimated 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, as reported in the partnerships' tax returns and such share of tax deductions as a percentage of their subscriptions. 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 PARTNERSHIP. TABLE 4 SUMMARY OF INVESTOR TAX BENEFITS AND CASH DISTRIBUTION RETURNS As of July 15, 2000
-------------------------------------------------------------------------------------------------------------------------- Estimated Federal Tax Savings From (1): ------------------------------------------------------------- 1st Year Eff. 1st Year Investor Tax Tax I.D.C. Depletion Section 29 Partnership Capital Deduct (2) Rate Deduct (3) Allowance (3) Depreciation (3) Tax Credit (4) ----------- ------- ---------- ---- ---------- ------------- ---------------- -------------- Atlas L.P. #1 - 1985 $600,000 99% 50.0% $298,337 $116,655 N/A $55,915 A.E. Partners-1986 631,250 99% 50.0% 312,889 64,217 N/A 13,507 A.E. Partners-1987 721,000 99% 38.5% 356,895 46,538 N/A N/A A.E. Partners-1988 617,050 99% 33.0% 244,351 42,558 N/A N/A A.E. Partners-1989 550,000 99% 33.0% 179,685 59,497 N/A N/A A.E. Partners-1990 887,500 99% 33.0% 275,125 79,438 N/A 234,190 A.E. Nineties-10 2,200,000 100% 33.0% 726,000 142,961 N/A 417,423 A.E. Nineties-11 750,000 100% 31.0% 232,500 83,739 N/A 267,473 A.E. Partners-1991 868,750 100% 31.0% 269,313 93,011 N/A 251,487 A.E. Nineties-12 2,212,500 100% 31.0% 685,875 170,425 N/A 497,871 A.E. Nineties-JV 92 4,004,813 92.5% 31.0% 1,322,905 284,782 N/A 756,727 A.E. Partners-1992 600,000 100% 31.0% 186,000 69,034 N/A 182,143 A.E. Nineties-Public #1 2,988,960 80.5% 36.0% 877,511 181,735 $246,143 N/A A.E. Nineties-1993 Ltd. 3,753,937 92.5% 39.6% 1,378,377 177,120 N/A N/A A.E. Partners-1993 700,000 100% 39.6% 273,216 70,068 N/A N/A A.E. Nineties-Public #2 3,323,920 78.7% 39.6% 1,036,343 146,214 254,264 N/A A.E. Nineties-14 9,940,045 95% 39.6% 3,739,445 381,587 N/A N/A A.E. Partners-1994 892,500 100% 39.6% 353,430 58,854 N/A N/A A.E. Nineties-Public #3 5,799,750 76.2% 39.6% 1,752,761 248,650 429,089 N/A A.E. Nineties-15 10,954,715 90.0% 39.6% 3,904,261 430,494 N/A N/A A.E. Partners-1995 600,000 100% 39.6% 237,600 18,890 N/A N/A A.E. Nineties-Public #4 6,991,350 80.0% 39.6% 2,214,860 208,126 412,316 N/A A.E. Nineties-16 10,955,465 86.8% 39.6% 3,361,289 250,005 663,202 N/A A.E. Partners-1996 800,000 100% 39.6% 316,800 25,944 N/A N/A A.E. Nineties-Public #5 7,992,240 84.9% 39.6% 2,530,954 186,594 399,437 N/A A.E. Nineties-17 8,813,488 85.2% 39.6% 2,966,366 202,055 317,274 N/A A.E. Nineties-Public #6 9,901,025 80.0% 39.6% 3,166,406 225,803 382,863 N/A A.E. Partners-1997 506,250 100% 39.6% 200,475 14,843 N/A N/A A.E. Nineties-18 11,391,673 90.0% 39.6% 4,030,884 209,989 171,156 N/A A.E. Nineties-Public #7 11,988,350 85.0% 39.6% 4,043,670 135,432 153,542 N/A A.E. Partners-1998 1,740,000 100.0% 39.6% 689,040 42,252 N/A N/A A.E. Nineties-19 15,720,450 90.0% 39.6% 5,602,767 93,632 38,434 N/A A.E. Nineties-Public #8 11,088,975 85.0% 39.6% 3,734,654 0 0 N/A A.E. Partners-1999 450,000 100.0% 39.6% 178,200 0 N/A N/A Cumulative Cash Percent of Distribution Total Cash Cash Dist. As of Dist. and and Tax Date of Tax Savings to Partnership Total Table (5) Savings Date ----------- ----- --------- ------- ---- Atlas L.P. #1 - 1985 $470,907 $1,336,573 $1,807,479 301% A.E. Partners-1986 390,613 639,925 1,030,538 163% A.E. Partners-1987 403,433 515,981 919,414 128% A.E. Partners-1988 286,909 472,008 758,917 123% A.E. Partners-1989 239,182 626,356 865,538 157% A.E. Partners-1990 588,753 809,303 1,398,056 158% A.E. Nineties-10 1,286,384 1,430,010 2,716,395 123% A.E. Nineties-11 583,712 870,403 1,454,115 194% A.E. Partners-1991 613,811 872,413 1,486,224 171% A.E. Nineties-12 1,354,171 1,633,629 2,987,799 135% A.E. Nineties-JV 92 2,364,414 3,252,883 5,617,297 140% A.E. Partners-1992 437,177 607,294 1,044,471 174% A.E. Nineties-Public #1 1,305,389 1,784,586 3,089,975 103% A.E. Nineties-1993 Ltd. 1,555,497 1,885,912 3,441,409 92% A.E. Partners-1993 343,284 685,426 1,028,710 147% A.E. Nineties-Public #2 1,436,821 1,577,057 3,013,878 91% A.E. Nineties-14 4,121,032 4,404,539 8,525,571 86% A.E. Partners-1994 412,284 646,819 1,059,103 119% A.E. Nineties-Public #3 2,430,500 2,683,908 5,114,408 88% A.E. Nineties-15 4,334,755 4,686,866 9,021,621 82% A.E. Partners-1995 256,490 254,307 510,797 85% A.E. Nineties-Public #4 2,835,302 2,083,878 4,919,181 70% A.E. Nineties-16 4,274,496 2,920,939 7,195,435 66% A.E. Partners-1996 342,744 232,572 575,316 72% A.E. Nineties-Public #5 3,116,985 2,125,563 5,242,547 66% A.E. Nineties-17 3,485,695 2,189,229 5,674,924 64% A.E. Nineties-Public #6 3,775,072 2,230,079 6,005,151 61% A.E. Partners-1997 215,318 113,831 329,149 65% A.E. Nineties-18 4,412,029 1,974,075 6,386,105 56% A.E. Nineties-Public #7 4,332,644 1,334,901 5,667,545 47% A.E. Partners-1998 731,292 332,371 1,063,663 61% A.E. Nineties-19 5,734,833 1,083,145 6,817,978 43% A.E. Nineties-Public #8 3,734,654 100,032 3,834,686 35% A.E. Partners-1999 178,200 0 178,200 40% ---------------------------------------------------------------------------------
(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. (2) The managing general partner anticipates that approximately 90% of an investor general partner's subscription to the partnership will be deductible in 2000. (3) The I.D.C. Deductions, Depletion Allowance and MACRS depreciation deductions have been reduced to credit equivalents. (4) The Section 29 tax credit is not available with respect to wells drilled after December 31, 1992. N/A means not applicable. (5) These distributions were all from production revenues. See footnotes 1 and 3 of Table 3. 27 Table 5 sets forth partnerships in which the managing general partner and its affiliates served as operator and/or drilling contractor for third party general partners as well as the partnerships in which Atlas served as managing general partner. The table includes the managing general partner's share of costs and revenues set forth in Table 3A, above. The managing general partner and its affiliates have drilled more than 3,600 wells over the 28-year period from 1972 to 2000. TABLE 5 ATLAS RESOURCES, INC. AND ITS AFFILIATES' HISTORICAL PRODUCTION RECORD As of July 15, 2000 (4)
-------------------------------------------------------------------------------------------------------------------------------- Last 3 Mo. Year Wells Total Total Amount Distribution Were Placed Total Mcf's Invested In Total Amount Cum % Return Ending As of Into Production Wells(1) Produced Wells(2) Returned(2) Cash-on-Cash (3) Date of Table --------------- ------- -------- ---------- -------------- ---------------- ------------- 1973 6 2,569,859 $576,000 $4,112,000 714% $14,476 1974 18 3,032,534 2,387,200 4,011,528 168% 12,124 1975 21 4,345,693 2,814,200 6,799,756 242% 23,032 1976 14 2,943,208 1,819,200 4,444,897 244% 11,102 1977 26 9,495,805 3,912,600 16,681,418 426% 61,541 1978 78 8,134,937 12,399,900 19,493,721 157% 69,004 1979 46 9,526,283 7,404,000 20,142,326 272% 60,343 1980 41 5,975,284 6,561,100 13,945,603 213% 46,712 1981 77 6,562,297 15,382,850 17,389,084 113% 34,280 1982 63 2,551,761 12,438,500 5,899,303 47% 14,392 1983 22 1,358,278 6,725,480 3,153,537 47% 16,474 1984 47 4,917,584 10,663,250 10,647,518 100% 47,888 1985 39 5,132,600 8,971,200 10,601,817 118% 47,398 1986 45 5,936,415 9,649,100 11,180,160 116% 82,520 1987 12 1,629,940 2,425,800 2,799,885 115% 15,152 1988 37 4,107,722 7,688,386 7,243,032 94% 63,526 1989 48 4,270,278 9,967,768 7,386,077 74% 63,662 1990 46 5,329,729 9,038,238 9,501,916 105% 70,262 1991 79 9,274,372 16,034,382 16,916,465 106% 196,849 1992 64 8,628,630 14,250,032 15,417,107 108% 196,874 1993 107 10,807,424 21,958,681 17,861,194 81% 128,912 1994 94 7,425,666 20,418,366 11,962,899 59% 276,468 1995 105 7,732,269 22,350,889 12,991,414 58% 352,443 1996 114 6,141,324 25,396,708 10,271,141 40% 356,411 1997 103 4,575,186 20,908,334 7,906,961 38% 451,721 1998 128 4,302,182 26,317,000 7,572,060 29% 634,075 1999 117 2,245,551 29,930,581 4,170,750 14% 2,288,913 2000 33 145,709 10,009,388 293,431 3% 286,118 ------- -------------- --------------- --------------- ---------- ------------ TOTAL 1,630 149,098,520 $338,399,133 $280,796,999 83% $5,922,671 ======= ============== =============== =============== ========== ============ --------------------------------------------------------------------------------------------------------------------------------
(1) The above numbers do not include information for: - 87 wells drilled for General Motors from 1971 to 1973 which were subsequently purchased by General Motors; - 25 wells successfully drilled in 1981 and 1982 for an industrial customer which requested that the wells be capped and not placed into production; - 127 wells drilled from 1980 to 1985 which were sold in 1993 and are no longer operated by the managing general partner; and - wells which were drilled recently but are not yet in production. (2) - The column "Total Amount Invested in Wells" only includes funds paid to the managing general partner or its affiliates as operator and/or drilling contractor for drilling and completing the designated wells. This column does not include all of the costs paid by investors to the third party managing general partner and/or sponsor of the program because such information is generally not available to the managing general partner or its affiliates. - Similarly, the column "Total Amount Returned" only includes amounts paid by the managing general partner or its affiliates as operator of the wells to the third party managing general partner and/or sponsor of the program. This column does not set forth the revenues which were actually received by the investors from the third party managing general partner and/or sponsor because such information is generally not available to the managing general partner or its affiliates. Notwithstanding, the columns "Total Amount Invested in Wells" and "Total Amount Returned" also include the partnerships in which Atlas serves as managing general partner and are presented on the same basis as the third party partnerships. (3) This column reflects total cash distributions beginning with the first production from the well, as a percentage of the total amount invested in the well, and includes the return of the investors' capital. (4) THE RESULTS OF TABLE 5 SHOULD BE VIEWED ONLY AS A MEASURE OF THE LEVEL OF ACTIVITY AND EXPERIENCE OF THE MANAGING GENERAL PARTNER WITH RESPECT TO DEVELOPMENT DRILLING PARTNERSHIPS. 28 MANAGEMENT MANAGING GENERAL PARTNER AND OPERATOR The managing general partner, Atlas, a Pennsylvania corporation, was incorporated in 1979, and its affiliate, Atlas Energy, an Ohio corporation, was incorporated in 1973. The managing general partner and its affiliates have acted as the operator and the general drilling contractor on approximately 3,650 gas wells, approximately 3,450 of which were capable of production in commercial quantities. As of December 31, 1999, the managing general partner and its affiliates operated approximately 3,400 oil or natural gas wells located in Ohio, Pennsylvania and New York. Since 1985 the managing general partner has sponsored 8 public and 26 private partnerships to conduct natural gas drilling and development activities in Pennsylvania and Ohio. 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. On September 29, 1998, Atlas Group, the former parent company of the managing general partner, merged into Atlas America, Inc., a newly formed wholly-owned subsidiary of Resource America, Inc. The merger was completed under an agreement and plan of merger dated July 13, 1998, and amended on September 29, 1998, by and among Resource America, Atlas America, Atlas Group and certain shareholders of Atlas Group. Resource America is a publicly-traded company principally engaged in energy, energy finance and real estate finance. Viking Resources was acquired in August 1999. Atlas America is continuing the existing business of Atlas Group and is headquartered at 311 Rouser Road, Moon Township, Pennsylvania 15108, near the Pittsburgh International Airport which is also the managing general partner's primary office. As of October 1, 1999, the Board of Directors for Atlas America includes the following:
NAME AGE POSITION OR OFFICE ---------------------- ---- ------------------ Edward E. Cohen 61 Chairman of the Board James R. O'Mara 57 Director Tony C. Banks 46 Director Michael L. Staines 51 Director Jonathan Z. Cohen 30 Director John S. White 60 Director JoAnn Bagnell 71 Director Charles T. Koval 66 Director James C. Eigel 66 Director
See " - Officers, Directors and Key Personnel," below, for biographical information on certain of these individuals who are also officers and/or directors of the managing general partner. Biographical information on the other directors will be provided by the managing general partner upon request. The managing general partner and its affiliates under Atlas America employ a total of approximately 154 persons, consisting of five geologists, eight landmen, six engineers, 33 operations staff, 14 accounting, one gas marketing, and 18 administrative personnel. The balance of the personnel are engineering, pipeline and field supervisors. Atlas America has been a leading participant in the energy finance industry for more than 28 years, providing drilling, operating and supervisory services for more than $380 million of independent investment now under Atlas America's management. 29 ORGANIZATIONAL DIAGRAM (1)(2) This organizational diagram does not include all of the subsidiaries of Resource America. ---------------------------------------- Resource America, Inc. ---------------------------------------- ---------------------------------------- Atlas America, Inc. ---------------------------------------- ---------------------------------------- AIC, Inc. ---------------------------------------- -------------------- --------------- ------- ------- ---- ---------- ----- ---------- ----------------- --------------- -------------- ------------- --------------- ---------------- Atlas Atlas Energy Transatco, Atlas Anthem Atlas Energy Resources, Corporation, Inc., which Information Securities Group, Inc., Inc., managing managing owns 50% of Management, Inc., driller and general general Topico, L.L.C., registered operator in partner, partner of operates markets broker-dealer Ohio driller and exploratory pipeline in information and operator in drilling Ohio and dealer-manager Pennsylvania partnerships technology and driller services and operator ----------------- --------------- -------------- ------------- --------------- ---------------- ---------------- -------------- ARD AED Investments, Investments, Inc. Inc. ---------------- --------------
------------------------------------------ (1) Resource Energy and Viking Resources, which are subsidiaries of Resource America, are also engaged in the oil and gas business. In the near term both Resource Energy and Viking Resources will retain their separate corporate existence, however, Atlas America will manage the assets and employees of both including sharing common employees. Also, many of the officers and directors of the managing general partner serve as officers and directors of those entities. (2) Atlas Pipeline Partners, L.P. (and Atlas Pipeline Operating Partnership) is a master limited partnership formed by a subsidiary of Atlas America as managing general partner which has acquired the natural gas gathering system and related facilities from Atlas America, Resource Energy, and Viking Resources. The gathering system consists of approximately 888 miles of intrastate pipelines located in Pennsylvania, Ohio, and New York. It is anticipated that this master limited partnership will gather and deliver the majority of the natural gas produced by the partnership to either industrial end-users in the area, local distribution companies, or interstate pipeline systems. OFFICERS, DIRECTORS AND KEY PERSONNEL 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 ---- --- ------------------ James R. O'Mara 57 President, Chief Executive Officer and a Director Tony C. Banks 46 Senior Vice President, Chief Financial Officer and a Director Michael L. Staines 51 Senior Vice President and Chief Operating Officer Frank P. Carolas 40 Vice President of Land and Geology Jeffrey C. Simmons 41 Vice President of Operations William R. Seiler 45 Assistant Secretary Barbara J. Krasnicki 54 Secretary
JAMES R. O'MARA. President, Chief Executive Officer and a Director. Mr. O'Mara also serves as Vice Chairman and a Director of Atlas America. Mr. O'Mara served with the United States Army Security Agency (ASA) and is a Vietnam veteran. Mr. O'Mara is a Certified Public Accountant and had been associated with Coopers and Lybrand, a national accounting firm, and Teledyne, Inc., a large conglomerate, before joining Atlas Energy in 1975. He is a member of the Pennsylvania Institute of Certified Public Accountants, and received a Bachelor of Science Degree in Accounting from Gannon University in 1968. 30 TONY C. BANKS. Senior Vice President, Chief Financial Officer, and a Director. Mr. Banks also serves as President, Chief Executive Officer and a Director of Atlas America. Mr. Banks has over 20 years of finance, accounting and administrative experience in the oil and gas industry, all with various subsidiaries of Consolidated Natural Gas Company. He started as an accounting clerk with CNG's parent company in 1974 and progressed through various positions with CNG's Appalachian producer, northeast gas marketer and southwest producer to his last position as treasurer of CNG's national energy marketing subsidiary. Mr. Banks served on CNG's corporate-wide financial accounting and planning, energy price risk and information services steering committees and has chaired the financial advisory and accounting research committees. In 1989, Mr. Banks was a seminar instructor for the University of Tulsa, and over the years has given presentations to industry groups on topics including energy derivatives, accounting for Appalachian gas imbalances and post regulation credit review and evaluation. He received a Bachelor of Science Degree in Accounting/Computers from Point Park College in Pittsburgh and passed the Pennsylvania Certified Public Accountant examination in 1988. Mr. Banks joined Atlas Group in 1995 and is Vice President of AIC, Inc., ARD Investments, Inc. and AED Investments, Inc. MICHAEL L. STAINES. Senior Vice President and Chief Operating Officer. Mr. Staines is also Secretary and Managing Director, Business Development of Atlas America and Atlas Pipeline Partners, and a Director of Atlas America since 1998, Senior Vice President and a Director of Resource America since 1998 and 1989, respectively, Secretary of Resource America from 1989 to 1998, and President, Chief Executive Officer and a Director of Resource Energy, the energy subsidiary of Resource America, since 1997. Mr. Staines is a member of the Ohio Oil and Gas Association and the Independent Oil and Gas Association of New York. Mr. Staines received a Bachelor of Science Degree from Cornell University in 1971 and a Master of Business Degree from Drexel University in 1977. FRANK P. CAROLAS. Vice President of Land and Geology. Mr. Carolas also serves as Vice President of Land and Geology of Atlas America and Viking Resources. Mr. Carolas is a certified petroleum geologist and has been with Atlas Energy 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. JEFFREY C. SIMMONS. Vice President of Operations. Mr. Simmons also serves as Vice President of Operations of Atlas America and Viking Resources. Mr. Simmons joined Resource America in 1986 as senior petroleum engineer. From 1988 through 1994 he served as director of production and as president of Resource Well Services, Inc., a subsidiary of Resource America. He was then promoted to vice president of Resource Energy, the energy subsidiary of Resource America formed in 1993. In 1997 he was promoted to executive vice president, chief operating officer and director of Resource Energy, a position he currently holds. Before Mr. Simmons' career with Resource America, he had worked with Core Laboratories, Inc., of Dallas, Texas, and PNC Bank of Pittsburgh. Mr. Simmons received his Petroleum Engineering degree from Marietta College and his Masters Degree in Business Administration from Ashland University. He is a Board Member of the Ohio Oil and Gas Association, the Independent Oil and Gas Association of New York and the Ohio Section of the Society of Petroleum Engineers. WILLIAM R. SEILER. Assistant Secretary. Mr. Seiler also serves as Vice President and Controller of Atlas America. Mr. Seiler had over 25 years of accounting, financial reporting, financial analysis, and mergers and acquisitions experience in the oil and gas industry with Consolidated Natural Gas Company before joining Atlas America and the managing general partner in July of 1999. Mr. Seiler joined CNG's corporate headquarters in 1974 as an accounting clerk and progressed to the final position as an officer of CNG as corporate assistant controller. Additional assignments with CNG included the corporate strategic financial planning department, manager of strategic financial planning, corporate-wide financial and accounting planning committee, and chair of the accounting research and financial forecasting committees. Mr. Seiler also served on the American Gas Association's statistics and load forecasting committee and was a member of the Bradford School Accounting Advisory Board. Mr. Seiler earned a Bachelor of Science degree in Accounting from Point Park College in Pittsburgh and holds a Masters Degree in Business Administration from Duquesne University. He is also member of the Beta Gamma Sigma Honor Society. BARBARA J. KRASNICKI. Secretary. Ms. Krasnicki has been with Atlas America and its predecessors since their inception in 1971. She was the office and personnel manager. She was elected secretary of the managing general partner in August, 1999. Ms. Krasnicki has an Associate in Science Degree from Point Park College, Pittsburgh, Pennsylvania. The officers and directors of AIC, Inc., which owns 100% of the common stock of the managing general partner, are Tony C. Banks and Norman J. Shuman. The biography of Mr. Banks is set forth above. 31 REMUNERATION No officer or director of the managing general partner will receive any direct remuneration or other compensation from the partnership. These persons will receive compensation solely from the managing general partner and its affiliated companies. The aggregate remuneration paid during the year ended September 30, 1999, to the five most highly compensated persons who were executive officers of the managing general partner and whose aggregate remuneration exceeded $100,000 and to all executive officers of the managing general partner as a group, for services in all capacities while acting as executive officers of the managing general partner and its affiliates, was as follows:
(A) (B) (C) (D) (E) NAME OF INDIVIDUAL OR NUMBER CAPACITIES IN WHICH SERVED CASH COMPENSATION AGGREGATE OF OF PERSONS IN GROUP (3) COMPENSATION (1) PURSUANT TO CONTINGENT FORMS OF PLANS (2) REMUNERATION ------------------------------- ---------------------------- ----------------------- ---------------------- ----------------------- James R. O'Mara President, Chief Executive $317,000 $5,000 -- Officer and a Director Charles T. Koval Chairman and a Director $240,614 $5,000 -- Tony C. Banks Senior Vice President, $200,968 $5,000 -- Chief Financial Officer, and a Director Frank P. Carolas Vice President of Land and $98,412 $5,000 -- Geology Jeffrey C. Simmons Vice President of $115,865 $8,646 -- Operations Executive Officers as a Group $1,034,985 $49,649 -- (7 persons) ------------------------------------
(1) The amounts indicated were composed of salaries and all cash bonuses for services rendered to the managing general partner and its affiliates, including compensation that would have been paid in cash but was deferred. (2) The managing general partner participates in a 401(k) plan which allowed employees to contribute the lesser of 15% of their compensation or $10,000 for the 1998 and 1999 calendar years. The managing general partner's parent company generally contributed an amount equal to 50% of each employee's contribution. However, this plan merged into the Resource America, Inc. Investment Savings Plan on September 1, 1999, which provided that for contributions up to 10% of the employee's compensation the employer would contribute in cash an amount equal to 50% of each employee's contribution or, at the employee's option, an amount of Resource America stock in an amount equal to 100% of the employee's contribution. Contributions in excess of 10% of an employee's compensation were not matched by the employer. (3) No director's fees were paid for the year to the directors of the managing general partner. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS Resource America owns 100% of the common stock of Atlas America, which owns 100% of the common stock of AIC, Inc., which owns 100% of the common stock of the managing general partner. TRANSACTIONS WITH MANAGEMENT AND AFFILIATES Pursuant to the merger of Atlas Group into Atlas America, the merger consideration paid to the shareholders of Atlas Group was 2,063,486 shares of Resource America's common stock and in addition options of 120,213, which were valued at $29,534,000 as of the date the definitive merger agreement was entered into, cash of $7,814,000 and the assumption of Atlas Group debt of $45,968,000. The exchange value of Resource America stock was based on a trading index using prices before the merger and did not reflect the trading price of the stock on the merger date. 32 Atlas Group shareholders received certain "piggy-back" registration rights, effective during the period from September 30, 1999 through September 29, 2000, for the shares of Resource America's common stock received by them. Atlas Group shareholders are also eligible to receive incentive compensation should Atlas Group's post-acquisition earnings exceed a specified amount during the four years following the merger. The incentive compensation is equal to 10% of Atlas Group's aggregate earnings in excess of that amount equal to an annual, but uncompounded, return of 15% on $63 million which is increased to include any amount paid by Resource America for any post-merger energy acquisitions. Incentive compensation is payable, at Resource America's option, in cash or in shares of Resource America's common stock, valued at the average closing price of Resource America's common stock for the 10 trading days before September 30, 2003. In addition, in November, 1990, Atlas Group and its shareholders had entered into agreements with Joseph Sadowski and Charles T. Koval, co-founders of Atlas Energy, to gradually liquidate a majority of their stock ownership in Atlas Group. The stock redemptions required Atlas Group to execute promissory notes, from time to time, in favor of Messrs. Koval and Sadowski. The first promissory notes had a principal amount of $4,974,340 each, plus interest at 13.5%. Under the merger, Atlas Group accelerated the promissory notes issued in the redemption, together with notes issued in a prior redemption of shares owned by Messrs. Koval and Sadowski, and these notes were paid in full at the time of closing of the merger. In connection with the merger, Mr. O'Mara exercised Atlas Group stock options resulting in $1,503,508 and Mr. Bruce Wolf, a retired director, exercised Atlas Group stock options resulting in $994,916. Also, under the terms of the merger, 13,106 stock options in Resource America were issued at an option price of $0.1069 per share to Mr. Banks. 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 on the same terms as unrelated investors. They may also subscribe for units in the partnership as described in "Plan of Distribution." PROPOSED ACTIVITIES OVERVIEW OF DRILLING ACTIVITIES The managing general partner anticipates that all the partnership's wells will be development wells, which means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. Also, the majority of the wells will be classified as gas wells which may produce a small amount of oil, although some of the wells may be classified as oil wells. Assuming the partnership acquires 100% of the interest in the wells, the managing general partner anticipates that the partnership will drill approximately : - 5.5 wells if the minimum subscriptions of $1 million are received; and - 80 wells if the maximum subscriptions of $15 million are received. The actual number of wells drilled by the partnership, however, may vary from these estimates and will depend on the following: - the amount of subscriptions proceeds received; - the partnership's percentage of the interest in the wells; and - where the wells are drilled. The managing general partner anticipates that the partnership generally will own 25% to 100% of the interest in its wells. Before selecting a well to be drilled by the partnership, the managing general partner will review all available geologic data for wells located in the vicinity of the proposed well including, but not limited to: 33 - logs; - completion reports; and - plugging reports. PRIMARY AREAS OF OPERATIONS As discussed below, the two primary areas for the partnership's drilling activities are the Clinton/Medina Geological Formation in Northwestern Pennsylvania and the Mississippian/Upper Devonian Sandstone reservoirs in Fayette County, Pennsylvania. The wells drilled to the Clinton/Medina geological formation and the Mississippian/Upper Devonian Sandstone reservoirs have the following similarities: - geological features such as structure and faulting are not generally factors used in finding commercial production from a well drilled to this formation or these reservoirs and the governing factors appear to be sand quality in terms of net pay zone thickness, porosity, and the effectiveness of fracture stimulation; - a well drilled to this formation or these reservoirs usually requires hydraulic fracturing of the formation to stimulate productive capacity; - generally, 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 production can be expected within the first several years; and - it has been the managing general partner's experience that gas production from wells drilled to this formation or these reservoirs is reasonably consistent within close proximity, although from time to time great differences in well performance can occur in wells located close together. THE CLINTON/MEDINA GEOLOGICAL FORMATION IN NORTHWESTERN PENNSYLVANIA. The managing general partner anticipates that if $1,000,000 is raised approximately 50% of the subscription proceeds will be used to drill approximately 3 wells, and if $15,000,000 is raised approximately 35% of the subscription proceeds will be used to drill approximately 31 wells, in Northwestern Pennsylvania in the Clinton/Medina geological formation. The Clinton/Medina geological formation is a blanket sandstone found throughout most of the northwestern edge of the Appalachian Basin. The Clinton/Medina is described in petroleum industry terms as a "tight" sandstone with porosity ranging from 6% to 12% and with very low permeability. 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. Based on the managing general partner's experience, it anticipates that all the partnership's wells will be completed and fraced in two different zones of the Clinton/Medina geological feature. See the geologic evaluation and the model decline curve prepared by United Energy Development Consultants, Inc., an independent geological and engineering firm for a discussion of the development of the Clinton/Medina Geological Formation in Northwestern Pennsylvania. The wells in the Clinton/Medina geological formation: - will be primarily situated in Mercer, Lawrence, Warren, Venango, and Crawford Counties; - will be situated on approximately 50 acres, subject to adjustment to take into account lease boundaries; - will not be drilled closer than approximately 1,650 feet to each other, which is greater than the 660 feet minimum area permitted by state law or local practice to protect against drainage from adjacent wells; - will be drilled from 5,100 to 6,300 feet in depth; 34 - will cost approximately $223,300 per well to drill and complete unless directional drilling tools are used which will increase the cost of the well by approximately $45,000; - will be classified as gas wells which may produce a small amount of oil; and - will be connected to the gathering system owned by Atlas Pipeline Partners and have their gas production marketed to First Energy Corporation as described below, although a portion of the gas production may be gathered by and sold to third parties if there were a third-party operator. Also, see "Secondary Areas" below, for a discussion of the Clinton/Medina geological formation in Ohio and New York. MISSISSIPPIAN/UPPER DEVONIAN SANDSTONE RESERVOIRS, FAYETTE COUNTY, PENNSYLVANIA. The managing general partner anticipates that if $1,000,000 is raised approximately 40% of the subscription proceeds will be used to drill approximately 2.5 wells, and if $15,000,000 is raised approximately 23% of the subscription proceeds will be used to drill approximately 20 wells, in Fayette County, Pennsylvania in the Mississippian/Upper Devonian Sandstone reservoirs. The Mississippian/Upper Devonian Sandstone reservoirs are discontinuous lens-shaped accumulations found throughout most of the Appalachian Basin. The Mississippian/Upper Devonian Sandstone reservoirs have porosities ranging from 5% to 20% with attendant permeabilities. See the managing general partner's geologic evaluation for a discussion of the development of the Mississippian/Upper Devonian Sandstone reservoirs in Fayette County, Pennsylvania. The wells in the Mississippian/Upper Devonian Sandstone reservoirs: - will be situated on approximately 20 acres, subject to adjustment to take into account lease boundaries; - will not be drilled closer than 1,000 feet to each other; - will be drilled from 1,900 to 4,500 feet in depth; - will cost approximately $223,900 per well to drill and complete; - will be classified as gas wells which may produce a small amount of oil; and - will be connected to the gathering system owned by Atlas Pipeline Partners and have their gas production marketed to First Energy Corporation as described below. SECONDARY AREAS OF OPERATIONS. The managing general partner also has reserved the right to use a portion of the subscription proceeds to drill development wells in other areas of the United States primarily in the Appalachian Basin. The secondary areas anticipated by the managing general partner are discussed below. CLINTON/MEDINA GEOLOGICAL FORMATION IN OHIO. Wells located in Ohio and drilled to the Clinton/Medina geological formation: - will be primarily situated in Mahoning, Portage, Trumbull, Noble, and Washington Counties. - will be situated on approximately 40 acres, subject to adjustment to take into account lease boundaries; - will not be drilled closer than approximately 1,000 feet to each other; - will be drilled from 4,900 to 6,300 feet in depth; 35 - will cost approximately $223,000 to drill and complete a gas well and approximately $230,000 to drill and complete an oil well unless directional drilling tools are used which will increase the cost of the well by approximately $45,000; - will have a 84.375% to 87.5% net revenue interest; - may be classified as either gas wells or oil wells; and - if classified as a gas well will be connected to the gathering system owned by Atlas Pipeline Partners and have its gas production marketed to First Energy Corporation as described below, although a portion of the gas production may be gathered by and sold to third parties if there were a third-party operator. CLINTON/MEDINA GEOLOGICAL FORMATION IN NEW YORK. Wells located in New York and drilled to the Clinton/Medina geological formation: - will be primarily situated in Chautauqua County; - will be situated on approximately 40 acres, subject to adjustment to take into account lease boundaries; - will be drilled from 3,800 to 4,000 feet in depth; - will cost approximately $223,300 per well to drill and complete; - will have a 84.375% to 87.5% net revenue interest; - will be classified as gas wells which may produce a small amount of oil; and - will be connected to the gathering system owned by Atlas Pipeline Partners and have their gas production marketed to First Energy Corporation as described below. MISSISSIPPIAN BEREA SANDSTONE IN OHIO. Wells located in Ohio and drilled to the Mississippian Berea Sandstone: - will be primarily situated in Columbiana County; - will be situated on approximately 5 acres, subject to adjustment to take into account lease boundaries; - will be drilled from 850 to 950 feet in depth; - will cost approximately $72,200 per well to drill and complete; - will have a 84.375% to 87.5% net revenue interest; - will be classified as gas wells which may produce a small amount of oil; and - will be connected to the gathering system owned by Atlas Pipeline Partners and have their gas production marketed to First Energy Corporation as described below. DEVONIAN ORISKANY SANDSTONE IN OHIO. Wells located in Ohio and drilled to the Devonian Oriskany Sandstone: - will be primarily situated in Tuscarawas County; 36 - will be situated on approximately 40 acres, subject to adjustment to take into account lease boundaries; - will be drilled from 3,800 to 4,200 feet in depth; - will cost approximately $230,225 per well to drill and complete; - will have a 84.375% to 87.5% net revenue interest; - will be classified as gas wells which may produce a small amount of oil; and - will be connected to the gathering system owned by Atlas Pipeline Partners and have their gas production marketed to First Energy Corporation as described below. KENTUCKY AND VIRGINIA. Wells in Kentucky and Virginia will be drilled to the following formations in descending order: Big Lime Limestone; Weir Sandstone; and the Cleveland, Upper Huron and Lower Huron members of the Devonian Shale. These wells: - will be primarily situated in Harlan County, Kentucky and Lee County, Virginia; - will be situated on approximately 70 acres, subject to adjustment to take into account lease boundaries; - will be drilled from 5,000 to 6,600 feet in depth; - will cost approximately $338,200 per well to drill and complete; - will have a 81.25% net revenue interest; - will be classified as gas wells which may produce a small amount of oil; and - will not be connected to the gathering system owned by Atlas Pipeline Partners, which is not situated in the area, and will have their gas production marketed to Duke Energy Marketing. ACQUISITION OF LEASES The managing general partner will have the right, in its sole discretion, to select the prospects which the partnership will drill. Currently, the managing general partner has proposed approximately 63% of the prospects to be drilled if all the units are sold. The leases covering the prospect on which each well will be drilled will be acquired from the managing general partner or its affiliates and credited to the managing general partner as a part of its required capital contribution. Neither the managing general partner nor its affiliates will receive any royalty or overriding royalty interest on any well. The managing general partner may substitute the prospects depending upon various considerations. The managing general partner anticipates that it will select any additional and/or substituted prospects from the following: - leases in its and its affiliates' existing leasehold inventory; - leases which are subsequently acquired by it or its affiliates; or - leases owned by independent third parties. Most of the additional and/or substituted prospects will be in areas where the managing general partner or its affiliates have previously conducted drilling operations and will meet the same general criteria for drilling potential as the currently proposed 37 wells. 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 well locations to be drilled by the partnership. The managing general partner and its affiliates are continually engaged in acquiring additional leasehold acreage in Pennsylvania and other areas of the United States. As of the date of this prospectus, the managing general partner and its affiliates owned approximately: - 93,674 net acres of undeveloped lease acreage in Pennsylvania; - 50,437 net acres of undeveloped lease acreage in Ohio; - 8,652 net acres of undeveloped lease acreage in West Virginia; - 2,370 net acres of undeveloped lease acreage in Kentucky; and - 13,643 net acres of undeveloped lease acreage in New York. Because the managing general partner will assign to the partnership only the number of prospects which it believes are necessary for the drilling operations of the partnership, the partnership will not farmout any acreage. Generally, a farmout is an agreement where the owner of the leasehold interest agrees to assign his interest in certain specific acreage to an assignee subject to the assignee drilling one or more specific wells as a condition of the assignment. The owner would retain some interest such as an overriding royalty interest which could revert to a working or operating interest at a designated time such as payout. DEEP DRILLING RIGHTS RETAINED BY MANAGING GENERAL PARTNER. In the areas where the Clinton/Medina is the primary geological formation, the lease assignments to the partnership will be limited to a depth of from the surface to the top of the Queenston geological formation. In the areas where the Mississippian/Upper Devonian Sandstone reservoirs are the primary targets, the lease assignments to the partnership will be limited to a depth of from the surface through the completion total depth of the well, and the managing general partner will retain the drilling rights below the completion total depth of the well. The managing general partner will retain the deeper drilling rights, because the partnership's objective is to conduct development drilling which would not be the case with the deeper formations. The managing general partner, however, believes that the partnership's development drilling in these areas will not provide any geological information that would assist it in evaluating drilling to deeper formations. Also, the amount of the credit the managing general partner receives for the partnership leases does not include any value allocable to the deeper drilling rights retained by it. If in the future geophysical or other exploratory activity is undertaken by the managing general partner on the deeper formations which provides a basis for the managing general partner drilling an exploratory well, then the partnership would not share in the profits from these activities. 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, any overriding royalty interests, and any interest in favor of third parties. Landowner's royalty interest generally means an interest which is created in favor of the landowner when an oil and gas lease is obtained, and overriding royalty interest generally means an interest which is created in favor of someone other than the landowner. In either case, the owner of the interest receives a specific percentage of the oil and gas production free and clear of all costs of development, operation, or maintenance of the well. 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 will share in from the wells in 38 the primary proposed areas. If the partnership acquires a lesser percentage ownership interest in a well, then the partnership's net revenue interest will decrease proportionately. PRIMARY AREAS. CLINTON/MEDINA GEOLOGICAL FORMATION IN NORTHWESTERN PENNSYLVANIA AND MISSISSIPPIAN/UPPER DEVONIAN SANDSTONE RESERVOIRS IN FAYETTE COUNTY, PENNSYLVANIA: - Before Net of Tax Savings Payout and Partnership Payout.
PARTNERSHIP THIRD PARTY 87.5% PARTNERSHIP ENTITY INTEREST ROYALTY INTEREST NET REVENUE INTEREST(1) ------ -------------- -------------------- ----------------------- Managing General Partner.................25% partnership interest (2) 21.875% Investors................................75% partnership interest (2) 65.625% Third Party.......................................................... 12.500% Landowner Royalty 12.500% Interest --------- 100.000% =========
--------------------------------- (1) It is possible that substituted or additional wells could have a net revenue interest to the partnership as low as 84.375% which would reduce the investors' interest to 63.281% (2). (2) These percentages are for illustration purposes only and are based on the managing general partner's minimum required capital contribution to the partnership compared to the corresponding capital contributions of 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. - After Net of Tax Savings Payout, but before Partnership Payout.
PARTNERSHIP THIRD PARTY 87.5% PARTNERSHIP ENTITY INTEREST ROYALTY INTEREST NET REVENUE INTEREST(1) ------ -------------- -------------------- ----------------------- Managing General Partner.................31.5% partnership interest (2) 27.5625% Investors................................68.5% partnership interest (2) 59.9375% Third Party.......................................................... 12.500% Landowner Royalty 12.5000% Interest --------- 100.0000% =========
--------------------------------- (1) It is possible that substituted or additional wells could have a net revenue interest to the partnership as low as 84.375% which would reduce the investors' interest to 57.7969% (2). (2) These percentages are for illustration purposes only and are based on the managing general partner's minimum required capital contribution to the partnership compared to the corresponding capital contributions of 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. - After Partnership Payout.
PARTNERSHIP THIRD PARTY 87.5% PARTNERSHIP ENTITY INTEREST ROYALTY INTEREST NET REVENUE INTEREST(1) ------ -------------- -------------------- ----------------------- Managing General Partner ................40% partnership interest (2) 35.000% Investors................................60% partnership interest (2) 52.500% Third Party.......................................................... 12.500% Landowner Royalty 12.500% Interest --------- 100.000% =========
--------------------------------- 39 (1) It is possible that substituted or additional wells could have a net revenue interest to the partnership as low as 84.375% which would reduce the investors' interest to 50.625% (2). (2) These percentages are for illustration purposes only and are based on the managing general partner's minimum required capital contribution to the partnership compared to the corresponding capital contributions of 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. SECONDARY AREAS. Although the managing general partner anticipates the partnership will have a net revenue interest ranging from 81% to 87.5% in the secondary areas described above, there is no minimum net revenue interest which the partnership is required to own before drilling a well in other areas of the Appalachian Basin or the United States. The leases in these other areas may be subject to interests in favor of third parties which 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 will be held in the name of the partnership. However, to facilitate the acquisition of the leases title to the leases may initially be held in the name of: - the managing general partner; - its affiliates; or - any nominee designated by the managing general partner. Title to the leases will be transferred to the partnership from time to time after the minimum subscriptions are received and released from escrow. After drilling, the title to the leases will be filed for record. 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 oil and gas industry to warrant title or obtain title insurance on leases and the managing general partner will provide neither for its lease interests assigned to the partnership. The managing general partner will obtain a favorable formal title opinion for the lease interest before each well is drilled, but the managing general partner may use its own judgment in waiving title requirements and will not be liable for any failure of title of leases transferred to the partnership. Also, there is no assurance that the partnership will not experience losses from title defects excluded from or not disclosed by the formal title opinion. DRILLING AND COMPLETION ACTIVITIES; OPERATION OF PRODUCING WELLS Under the drilling and operating agreement the responsibility for drilling and completing, or plugging, partnership wells will be on the managing general partner or an affiliate as the operator and the general drilling contractor for cost plus 15% as described in 40 "Compensation." During drilling operations the managing general partner's duties as operator and general drilling contractor will include: - making necessary arrangements for drilling and completing partnership 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 technical decisions required in drilling and completing the wells. Under the drilling and operating agreement all partnership wells will be drilled to a sufficient depth to test thoroughly the objective geological formation, and the partnership will prepay the investors' share of the drilling and completion costs. If there is a co-owner of the well which serves as the actual operator and the general drilling contractor, then the managing general partner will still enter into the drilling and operating agreement with the partnership to drill and complete the wells on the terms described in "Compensation." This may include a few of the wells drilled in the Clinton/Medina geological formation in Northwestern Pennsylvania and Ohio and the Devonian Shale geological formation in Kentucky and Virginia. The managing general partner would review the performance of the third-party operator and general drilling contractor which would include the following: - monitoring all field operations in connection with drilling, testing and equipping the wells; - monitoring technical decisions required in drilling and completing the wells; - monitoring the costs and expenses charged by the third party operator; and - monitoring the accounting and production records for the partnership. If the partnership is the largest interest owner in the well, then it is likely that even in these circumstances the managing general partner would control the operations through its ownership interest in the well. Under the drilling and operating agreement the managing general partner, as operator, will complete each well if there is a reasonable probability of obtaining commercial quantities of oil or gas. However, based upon its past experience, the managing general partner anticipates that most of the partnership's wells drilled to the Clinton/Medina geological formation and the Mississippian/Upper Devonian Sandstone reservoirs will be required to be completed before it can determine the well's productivity. If the managing general partner, as operator, 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 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 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. The drilling and operating agreement contains a number of other material provisions which you and the other prospective investors should carefully review. 41 If the managing general partner or an affiliate is not the actual operator of the well during producing operations as described above, then the managing general partner will enter into the drilling and operating agreement and receive well supervision fees for reviewing the performance of the third party operator. This includes the following: - reviewing the costs and expenses charged by the third party operator; and - monitoring the accounting and production records for the partnership. The actual operator will perform services for each well which are customarily performed to operate a well in the same general area as where the well is located. The third party operator will be reimbursed for its direct costs and will receive either reimbursement of its administrative overhead or well supervision fees pursuant to an operating agreement. In these cases these fees will be paid by the managing general partner from the well supervision fees it receives under the drilling and operating agreement entered into between the managing general partner and the partnership. As described above, certain wells may be drilled with third parties owning a portion of the interest in the wells. Any other interest owner in a well may have a separate agreement with the managing general partner with respect to the drilling and operating of the well with differing terms and conditions from those contained in the partnership's drilling and operating agreement. SALE OF OIL AND GAS PRODUCTION POLICY OF TREATING ALL WELLS EQUALLY IN A GEOGRAPHIC AREA. The managing general partner is responsible for selling the partnership's gas and oil production, and its policy is to treat all wells in a given geographic area equally. This reduces certain potential conflicts of interest among the owners of the various wells, including the partnership, concerning to whom and at what price the gas and oil will be sold. For example, the managing general partner calculates a weighted average selling price for all of the gas sold in the geographic area by dividing the money received from the sale of all of the gas sold to customers in the area by the volume of all gas sold from the wells in the area. For gas sold in Northwestern Pennsylvania the managing general partner received an average selling price after deducting all expenses, including transportation expenses, of approximately: - $2.39 per mcf in 1997; - $2.22 per mcf in 1998; - $2.35 per mcf in 1999; and - $2.80 per mcf for the first six months of 2000. Although on occasion the managing general partner has reduced the amount of production it normally sells on the spot market until the spot market price increased, the managing general partner has not voluntarily restricted its gas production in the past five years because of a lack of a profitable market price. If the managing general partner should decide that curtailment of production would be in the best interests of its partnerships, then production will be curtailed to the same degree in all the wells in the same geographic area. On the other hand, if the managing general partner has not decided to curtail production, but all the gas produced cannot be sold because of limited demand for the gas, which increases pipeline pressure, then the production that is sold will be from those wells which are able to feed into the pipeline, regardless of which partnerships own the wells. GATHERING OF THE GAS. With respect to the majority of the partnership's natural gas production, including gas in the primary areas of Northwestern Pennsylvania and Fayette County, Pennsylvania, Atlas Pipeline Partners, L.P., a limited partnership in which a subsidiary of Atlas America serves as managing general partner, will gather, compress and transport the gas to industrial 42 end-users, local distribution companies, or interstate pipeline systems as discussed below. If the partnership's gas is not transported through the Atlas Pipeline Partners gathering system, then it is because there is a third-party operator or the gathering system has not been extended to the wells. In these cases the gas will be transported through a third-party gathering system and the partnership will pay a competitive fee. As a part of the sale of the gathering system to Atlas Pipeline Partners, Atlas America and its affiliates, Resource Energy and Viking Resources, made the commitments set forth below which to varying degrees may affect the partnership. The commitments were intended to maximize the use and expansion of the gathering system. These are continuing obligations of Atlas America, Resource Energy, and Viking Resources unless the managing general partner of Atlas Pipeline Partners is removed without cause in which case the obligations cease. - They are required to pay a gathering fee equal to the greater of $0.35 per mcf or 16% of the gross sales price for each mcf transported for all partnerships in which their subsidiaries serve as managing general partner, which includes the partnership. Gross sales price generally means the price received by the seller, for natural gas sold by it, without deduction for brokerage fees, commissions, or offsets. Thus, if the partnership pays a lesser amount as is currently anticipated by the managing general partner as described in "Compensation - Gathering Fees," then Atlas America or one of the other parties must pay the difference to Atlas Pipeline Partners. - They committed to adding 225 wells to the gathering system over a period from January 1, 1999, until December 31, 2002, which includes any well drilled in a partnership sponsored by them. To satisfy the commitment the wells must be drilled within 2,500 feet of the gathering system and the well owner must construct up to 2,500 feet of small diameter sales or flow lines from the wellhead to the gathering system. This commitment has been satisfied. - With respect to wells drilled more than 3,500 feet from the gathering system, Atlas Pipeline Partners may, at its cost, extend its gathering systems to within 2,500 feet. If it does not, then the well may be connected to a third party pipeline, a local distribution company or an end user. If the wells are to be connected to a third party gathering system, however, Atlas Pipeline Partners has the right to pay the cost of constructing the line from the well to the third party gathering system. If it does so, it will own the line and will be paid an amount equal to the greater of $0.35 per mcf or 16% of the gross sales price for each mcf transported, less the gathering fee charged by the other gathering system. - They have agreed to assist Atlas Pipeline Partners in identifying existing gathering systems for possible acquisition and provide consulting services in evaluating and bidding for these systems. - They have agreed that their subsidiaries which currently serve as managing general partners of their drilling programs will continue to serve as managing partners of new drilling programs, and a managing general partner's interests in a drilling program may not be transferred to a person unless it transfers its ownership in each of its other drilling programs to the same person. - Atlas America has agreed to provide construction management and financing services to Atlas Pipeline Partners in the construction of additions or extensions to the gathering system. For a period of five years from January 28, 2000 to January 28, 2005 Atlas America has a standby commitment for a maximum of $1.5 million in any contract year. The funds will be provided through the purchase by Atlas America of Atlas Pipeline Partners' common units in the amount of the construction costs. GAS CONTRACTS. The managing general partner, Resource Energy, Inc. and Atlas Energy Group, Inc. have a gas supply agreement with First Energy Corporation through its affiliate, Northeast Ohio Gas Marketing, for a 10-year term which began on April 1, 1999. Subject to certain exceptions, First Energy Corporation must buy all of the gas produced and delivered by the managing general partner and its affiliates, which includes the partnership, at certain delivery points with the facilities of: East Ohio Gas 43 Company, National Fuel Gas Distribution, and Peoples Natural Gas Company, which are local distribution companies, and National Fuel Gas Supply, Columbia Gas Transmission Corporation, and Tennessee Gas Pipeline Company, which are interstate pipelines. First Energy Corporation is an electric utility listed on the New York Stock Exchange which also provides natural gas to industry and retail consumers. Generally, all of the managing general partner's and its affiliates' gas is subject to the agreement with First Energy Corporation, with the following exceptions: - gas being sold to Wheatland Tube Company, CSC Industries and Warren Consolidated, which are industrial end-users and direct delivery customers of the managing general partner and its affiliates; - gas which at the time of the agreement was already dedicated for the life of the well to another buyer; - gas which is produced by a company which was not an affiliate of the managing general partner at the time of the agreement; - gas which is produced in areas where there is not a delivery point into any of the interstate pipelines or local distribution companies described above; or - gas which is produced from a well which is being operated by a third-party and as a part of the acquisition it was agreed that the third-party operator would market the gas. The contract with Wheatland Tube currently provides for more favorable pricing than under the agreement with First Energy Corporation. The contracts with CSC and Warren Consolidated will be unrelated to the partnership. The agreement establishes a price formula for each of the delivery points for either the first one or two years of the agreement which is tied to the spot market price. If, at the end of the applicable period, the parties cannot agree to a new price for any delivery point, then the managing general partner and its affiliates may arrange a sale of their gas for that delivery point to a third-party for 12 months. If First Energy Corporation does not match this price, then the gas will be sold to the third-party. This process will be repeated each year. The contracts with National Fuel Resources, Inc. and NUI Energy Brokers, Inc. discussed below were entered into pursuant to this process. The agreement may be suspended for force majeure which means generally such things as an act of God, fire, storm, flood, and explosion, but also includes the permanent closing of the factories of Carbide Graphite or Duferco Farrell Corporation during the term of First Energy Corporation's agreements to sell gas to them. If these factories were closed, however, the managing general partner believes that First Energy Corporation would be able to find alternative purchasers and would not invoke the force majeure. The managing general partner anticipates that the gas produced by the partnership from wells drilled to the Clinton/Medina geological formation in Northwestern Pennsylvania will be sold to the following customers. - Approximately 10% to 15% to Wheatland Tube pursuant to an agreement that contains minimum and maximum prices that are fixed over each annual period. - Approximately 40% to National Fuel Resources, Inc., a marketing subsidiary of National Fuel Gas Company, which is a publicly traded company that distributes natural gas to approximately 744,000 customers in Southwest New York and Northwest Pennsylvania through its regulated utility divisions, pursuant to an agreement for successive one year terms beginning April 1, 2000. - Approximately 17% to NUI Energy Brokers, Inc., a marketing subsidiary of NUI Corporation, a publicly traded company that distributes natural gas to approximately 372,000 customers in six states through its regulated utility divisions, pursuant to an agreement for successive one year terms beginning April 1, 2000. - The remainder of the partnership's gas will be sold to First Energy Corporation as discussed above. 44 All of these agreements include monthly pricing formulas for the gas for each of the delivery points set forth in the respective agreements. Also, since the agreements with National Fuel Resources and NUI Energy Brokers, the managing general partner and First Energy Corporation have been able to agree to new pricing arrangements for other delivery points pursuant to their agreement. At the end of the one year term, which is April 1, 2001, First Energy Corporation will have the opportunity to again buy the gas at the delivery points which are currently under the agreements with National Fuel Resources and NUI Energy Brokers. The managing general partner anticipates that all of the gas produced by the partnership from wells drilled to the Mississippian/Upper Devonian Sandstone reservoirs in Fayette County, Pennsylvania will be sold to First Energy Corporation. The marketing of natural gas production has been influenced by the availability of certain financial instruments, such as gas futures contracts, options and swaps which, when properly used as hedge instruments, provide producers or consumers of gas with the ability to lock in the price which will ultimately be paid for the future deliveries of gas. The managing general partner is using financial instruments to hedge the price risk of a portion of its partnerships' gas production, which would include the partnership. 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 hedging policies and procedures. The managing general partner does not intend to contract for positions that it cannot offset with actual production. MARKETING OF GAS PRODUCTION FROM WELLS IN OTHER AREAS OF THE UNITED STATES. The managing general partner expects that gas produced from wells drilled in areas of the United States other than described above will be primarily tied to the spot market price and supplied to: - gas marketers; - local distribution companies; - industrial end-users; and/or - electric companies. CRUDE OIL. Crude oil produced from the 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. Thus, crude oil does not present any transportation problem. The managing general partner anticipates selling any oil produced by the wells to purchasers in spot sales. The managing general partner was receiving an average selling price for oil of approximately: - $15.20 per barrel in December, 1997; - $13.00 per barrel in December, 1998; - $16.20 per barrel in 1999; and - $25.00 per barrel for the first six months of 2000. Over the past eight years, the price of oil has ranged from approximately $38 to as low as $8 per barrel. There can be no assurance as to the price of oil during the term of the partnership. INSURANCE Since 1972, the managing general partner and its affiliates, including its partnerships, have been involved in the drilling of more than 3,600 wells in Ohio, Pennsylvania and other areas of the Appalachian Basin. They have not incurred a blow-out, fire or similar hazard with any of these wells, and thus have not made any insurance claims. The managing general partner will obtain and maintain insurance coverage in amounts and for purposes which would be carried by a reasonable, prudent general contractor and operator in accordance with industry standards. The partnership will be named as an 45 additional insured under these 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. 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; - liability insurance, including automobile, which has a $1 million combined single limit for bodily injury and property damage in any one occurrence or accident and in the aggregate; and - excess liability insurance as to bodily injury and property damage with combined limits of $50 million during drilling operations and $10 million thereafter, per occurrence or accident and in the aggregate. - This includes $1,000,000 of seepage, pollution and contamination insurance which protects the insured against bodily injury or property damage claims from third parties, other than a co-owner of the interest in the well, alleging seepage, pollution or contamination damage resulting from an accident. The excess liability insurance will be effective no later than the date subscription proceeds are first released from escrow, and will insure the partnership and the managing general partner's other partnerships until the investor general partners are converted to limited partners. After conversion the partnership will have the benefit of the managing general partner's $11 million liability insurance on the same basis as the managing general partner and its affiliates, including the managing general partner's other partnerships. Because the managing general partner is driller and operator of other partnerships there is a risk that the insurance available to the partnership could be substantially less if there are claims with respect to the other partnerships. These policies will have terms, including exclusions and deductibles, standard for the oil and gas industry. Upon 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 which meets its current coverage, but may be unsuccessful if the coverage becomes unavailable or too expensive. If you are an investor general partner and there is going to be an adverse material change in the partnership's insurance coverage, which is not anticipated, then the managing general partner must notify you at least 30 days before the effective date. If the insurance coverage is materially reduced, then you will have the right to convert your units into limited partner interests before the reduction by giving written notice to the managing general partner. USE OF CONSULTANTS AND SUBCONTRACTORS The partnership agreement authorizes the managing general partner to use the services of independent outside consultants and subcontractors who will normally be paid on a per diem or other cash fee basis. The services 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 unaccountable, fixed payment reimbursement paid to the managing general partner for administrative costs, and well supervision fees paid to the managing general partner as operator. 46 INFORMATION REGARDING CURRENTLY PROPOSED WELLS Set forth below is information relating to wells which have been currently proposed to be drilled by the partnership when subscription proceeds are released from escrow and from time to time thereafter subject to the managing general partner's right to withdraw the wells and to substitute other wells. The specified wells represent the necessary wells if approximately $9.5 million is raised and the partnership takes 100% of the interest in the wells. It is not anticipated that the well locations will be selected in the order in which they are set forth. The managing general partner has not proposed any other wells if any of the following occur: - a greater amount is raised; - the partnership takes a lesser interest in the wells; - the wells are substituted; or - the managing general partner decides to drill wells in other areas of the United States. The managing general partner has not authorized any person to make any representations to you concerning the possible inclusion of any other wells in the partnership and you and the other prospective investors should rely only on the information in this prospectus. The currently proposed wells will be assigned unless circumstances occur which, in the managing general partner's opinion, lessen the relative suitability of the wells. These considerations include: - the amount of the subscription proceeds; - the latest geological data available; - potential title problems; - approvals by federal and state departments or agencies; - agreements with other interest owners in the wells; - continuing review of other properties which may be available; and - if no other circumstances occur which in the managing general partner's opinion diminish the relative attractiveness of the proposed wells. Any substituted and/or additional wells will meet the same general criteria for development potential as the currently proposed wells and will generally 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 geophysical, geological, economic or other information regarding the substituted and/or additional wells. The purpose of the information regarding the currently proposed wells is to help you in evaluating the proposed wells, including production information for wells in the general area which the managing general partner believes is an important indicator in evaluating the economic potential of any well to be drilled. There, however, can be no assurance that a well drilled by the partnership will experience production comparable to the production experienced by wells in the surrounding area since the geological conditions in these areas can change in a short distance. You are cautioned to analyze carefully all production information for each well offsetting or in the general area of a well proposed to be drilled by the partnership. In your analysis you should weigh the factors set forth below. 47 - The length of time which the well has been on line and the period for which production information is shown. - The impact of "flush" production of a well which usually occurs in the early period of well operations. This period can vary depending on the location of the well and the manner in which the well is operated. - Production from a well declines at various rates throughout the life of the well and decline curves vary depending on the geological location of the well and the manner in which the well is operated. - The production information for some wells is incomplete and with other wells very limited. The designation "N/A" means: - the production was not available to the managing general partner; or - if the managing general partner was the operator, then the well was not completed or on line as of the date of the report. - Production information for wells located close to a proposed well tends to be more relevant than production information for wells farther from a proposed well, although from time to time great differences in well performance can occur in wells located close together. - Consistency in production among wells tends to confirm the reliability and predictability of the production. To help you in becoming familiar with the proposed wells the information set forth below is included. - Northwestern Pennsylvania (Clinton/Medina Geological Formation). - A map of western Pennsylvania and eastern Ohio showing their counties. - Lease information. - A Location and Production Map showing the proposed wells and the wells in the area. - Production data. - United Energy Development Consultants, Inc.'s geologic evaluation. - Fayette County, Pennsylvania (Mississippian/Upper Devonian Sandstone Reservoirs). - A map of western Pennsylvania showing Fayette County. - Lease information. - A Location and Production Map showing the proposed wells and the wells in the area. - Production data. - The managing general partner's geologic evaluation. 48 MAP OF WESTERN PENNSYLVANIA AND EASTERN OHIO 49 [MAP] 50 LEASE INFORMATION 51
OVERRIDING ROYALTY INTEREST TO THE EFFECTIVE EXPIRATION LANDOWNER ROYALTY MANAGING GENERAL PROSPECT NAME COUNTY DATE* DATE* PARTNER ----------------------------- ----------------- --------------- ---------------- ------------------ -------------------- 1. Elder #2 Lawrence 03/08/02 03/08/02 12.5% 0% 2. Griffith #1 Lawrence 09/21/99 09/21/02 12.5% 0% 3. Griffith #2 Lawrence 09/21/99 09/21/02 12.5% 0% 4. Kauffman #2 Lawrence 04/27/98 04/27/01 12.5% 0% 5. Lahr #1 Lawrence 06/25/99 06/25/02 12.5% 0% 6. Mast #9 Lawrence 07/24/98 07/24/01 12.5% 0% 7. McConnell #2 Lawrence 08/13/98 08/13/01 12.5% 0% 8. Miller #15 Lawrence 10/28/99 10/28/02 12.5% 0% 9. Patterson #2 Lawrence 10/19/99 10/19/02 12.5% 0% 10. Porada #1 Lawrence 06/04/99 06/04/02 12.5% 0% 11. R. & K. Partners #1 Lawrence 11/16/99 11/16/02 12.5% 0% 12. Reiber #1 Lawrence 01/26/99 01/26/02 12.5% 0% 13. Rose #1 Lawrence 12/21/99 12/21/02 12.5% 0% 14. Wengerd #6 Lawrence 01/26/99 01/26/02 12.5% 0% 15. White #6 Lawrence 10/02/98 10/02/01 12.5% 0% 16. Wilson #7 Lawrence 03/12/99 03/12/02 12.5% 0% 17. Burgoon #1 Mercer 05/25/00 05/25/03 12.5% 0% 18. Byler #83 Mercer 06/21/00 06/21/03 12.5% 0% 19. Byler #84 Mercer 10/14/99 10/14/02 12.5% 0% 20. Garrett #8 Mercer 09/09/98 09/09/03 12.5% 0% 21. Jovenall #2 Mercer 06/18/98 HBP 12.5% 0% 22. King #6 Mercer 06/28/99 06/28/02 12.5% 0% 23. Lutz #3 Mercer 06/25/00 06/25/03 12.5% 0% 24. McFarland #19 Mercer 10/08/97 10/08/00 12.5% 0% 25. Minner #7 Mercer 05/07/98 HBP 12.5% 0% 26. Revale #1 Mercer 10/08/99 10/08/02 12.5% 0% 27. Schwartz #2 Mercer 07/16/98 07/16/01 12.5% 0% 28. Shetler #3 Mercer 03/23/72 HBP 12.5% 0% 29. Webster #1 Mercer 06/19/99 06/19/02 12.5% 0% 30. Weimer #1 Mercer 01/04/00 01/04/03 12.5% 0% OVERRIDING ROYALTY ACRES TO BE INTEREST TO NET REVENUE NET ACRES ASSIGNED TO PROSPECT NAME 3RD PARTIES INTEREST PARTNERSHIP ----------------------------- -------------------- ---------------- ---------- --------------- 1. Elder #2 0% 87.5% 148.00 50.00 2. Griffith #1 0% 87.5% 51.17 50.00 3. Griffith #2 0% 87.5% 93.59 50.00 4. Kauffman #2 0% 87.5% 92.00 50.00 5. Lahr #1 0% 87.5% 39.00 50.00 6. Mast #9 0% 87.5% 80.00 50.00 7. McConnell #2 0% 87.5% 75.00 50.00 8. Miller #15 0% 87.5% 59.00 50.00 9. Patterson #2 0% 87.5% 98.60 50.00 10. Porada #1 0% 87.5% 63.00 50.00 11. R. & K. Partners #1 0% 87.5% 82.00 50.00 12. Reiber #1 0% 87.5% 126.00 50.00 13. Rose #1 0% 87.5% 81.00 50.00 14. Wengerd #6 0% 87.5% 54.00 50.00 15. White #6 0% 87.5% 107.00 50.00 16. Wilson #7 0% 87.5% 104.00 50.00 17. Burgoon #1 0% 87.5% 58.00 50.00 18. Byler #83 0% 87.5% 100.00 50.00 19. Byler #84 0% 87.5% 102.00 50.00 20. Garrett #8 0% 87.5% 50.00 50.00 21. Jovenall #2 0% 87.5% 132.00 50.00 22. King #6 0% 87.5% 35.00 50.00 23. Lutz #3 0% 87.5% 160.00 50.00 24. McFarland #19 0% 87.5% 133.00 50.00 25. Minner #7 0% 87.5% 205.00 50.00 26. Revale #1 0% 87.5% 65.00 50.00 27. Schwartz #2 0% 87.5% 110.00 50.00 28. Shetler #3 0% 87.5% 60.00 50.00 29. Webster #1 0% 87.5% 140.00 50.00 30. Weimer #1 0% 87.5% 60.00 50.00
-------------------------------- *HBP - Held by Production 52 LOCATION AND PRODUCTION MAP 53 [MAP] 54 [MAP] 55 [MAP] 56 [MAP] 57 [MAP] 58 [MAP] 59 PRODUCTION DATA 60
The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership. ID DATE MOS TOTAL TOTAL LATEST NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY CLINTON/MEDINA DEPTH PROD. ----------------------------------------------------------------------------------------------------------------------------- 20187 Atlas Resources, Inc. Wengerd Unit #2A 03/22/98 24 26361 6075 756 20195 Atlas Resources, Inc. Byler #33 01/11/99 16 28675 6098 1200 20203 Atlas Resources, Inc. Teh #1 09/18/98 20 24243 5999 734 20216 Atlas Resources, Inc. Kempf #3 02/03/99 16 16097 6087 630 20245 Atlas Resources, Inc. Buchowski #2 07/14/99 10 59931 6111 8707 20246 Atlas Resources, Inc. Contray #1 09/25/99 8 17825 6087 1994 20247 Atlas Resources, Inc. Johnston Unit #5 08/20/99 9 12311 6085 921 20272 Atlas Resources, Inc. Best #3 11/01/99 2 4554 6292 2608 20273 Atlas Resources, Inc. Grata #1 01/26/00 2 3346 6000 2468 20274 Atlas Resources, Inc. Mitcheltree #1 01/09/00 2 5668 6279 3417 20275 Atlas Resources, Inc. Shaffer Unit #6 01/04/00 2 6813 6337 3774 20276 Atlas Resources, Inc. Wengerd #7 02/01/00 N/A N/A 6132 N/A 20277 Atlas Resources, Inc. Stickle #1 01/23/00 3 2390 6297 944 20279 Atlas Resources, Inc. Byler #73 01/08/00 3 3389 6272 1594 20280 Atlas Resources, Inc. Byler #72 01/12/00 3 562 6283 307 20281 Atlas Resources, Inc. Braatz #1 01/14/00 2 5573 6332 3285 20283 Atlas Resources, Inc. Telesz #1 01/17/00 2 3955 6311 2276 20285 Atlas Resources, Inc. Kendall #2 02/01/00 N/A N/A 6315 N/A 20286 Atlas Resources, Inc. Clark #7 02/14/00 1 1239 6326 N/A 20291 Atlas Resources, Inc. Kauffman #1 02/13/00 N/A N/A 6156 N/A 20292 Atlas Resources, Inc. Telesz #2 03/13/00 2 3585 6317 2298 20293 Atlas Resources, Inc. Wilson #6 02/07/00 N/A N/A 6197 N/A 20392 Atlas Resources, Inc. Hillmar Unit #9 02/22/82 170 49014 6234 576 20604 Atlas Resources, Inc. Nych Unit #1 05/05/84 149 32650 5652 159 20740 Atlas Resources, Inc. Five Brothers #1 11/03/85 173 38452 5513 N/A 20867 Atlas Resources, Inc. Valentine #1 03/07/88 147 40954 5545 127 20873 Cabot Oil & Gas Nader #2 11/23/80 N/A N/A 5121 N/A 21121 Capital Oil & Gas Hostetler, M. & D. #1 11/11/90 N/A N/A 6140 N/A 21126 Atlas Resources, Inc. Stambaugh #2 02/06/91 110 90115 5528 596 21231 Capital Oil & Gas Cox, Joan #1 12/23/91 N/A N/A 6100 N/A 21368 Atlas Resources, Inc. Moose #3 08/29/92 89 59946 5906 169 21497 Capital Oil & Gas Byler, S. & M. #2 12/02/92 N/A N/A 6210 N/A 61 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership. ID DATE MOS TOTAL TOTAL LATEST NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY CLINTON/MEDINA DEPTH PROD. ----------------------------------------------------------------------------------------------------------------------------- 21498 Capital Oil & Gas Hostetler, M. & D. #3 10/29/92 N/A N/A 6154 N/A 21508 Capital Oil & Gas Cox, J. #2 12/17/92 N/A N/A 6035 N/A 21569 Tipka Oil & Gas Byler, J. & K. #1 09/19/92 N/A N/A 6036 N/A 21577 Atlas Resources, Inc. Symons #1 09/19/92 89 41310 5950 114 21582 Tipka Oil & Gas Janosky Unit #1 10/02/92 N/A N/A 5882 N/A 21590 Tipka Oil & Gas McFarland Unit #1 10/20/92 N/A N/A 5864 N/A 21591 Atlas Resources, Inc. Hover #1 10/07/92 89 55269 6001 247 21614 Atlas Resources, Inc. Byler #3 12/15/92 88 117438 6037 509 21617 Atlas Resources, Inc. Williams Unit #2 12/19/92 88 134340 5901 674 21642 Atlas Resources, Inc. Hover Unit #2 01/10/93 88 76626 5999 536 21663 Atlas Resources, Inc. Ammer #6 03/01/93 86 78790 6196 466 21664 Atlas Resources, Inc. Byler #4 06/28/93 83 144579 6022 1055 21666 Atlas Resources, Inc. Moose #8A 12/05/93 78 76575 6121 539 21669 Atlas Resources, Inc. Byler #7A 07/07/93 83 60371 6182 481 21672 Atlas Resources, Inc. Moose Unit #6 12/12/93 76 64776 5975 567 21677 Atlas Resources, Inc. Moose #5 02/17/93 86 81195 6052 365 21678 Atlas Resources, Inc. Byler Unit #6 11/03/93 79 66691 6135 440 21679 Atlas Resources, Inc. Swartzentruber #2 11/09/93 Plugged & Abandoned 6177 N/A 21680 Atlas Resources, Inc. Edeburn Unit #1 11/14/93 78 46764 6060 370 21715 Atlas Resources, Inc. McCutcheon #1 02/23/93 86 78026 5978 303 21745 North Coast Energy Ray, F. & E. #1 10/15/93 N/A N/A 5900 N/A 21806 Atlas Resources, Inc. Kirk #1 02/12/94 74 63352 6212 325 21845 Atlas Resources, Inc. Swartzentruber #1 01/07/94 76 42101 6123 329 21922 Atlas Resources, Inc. Kirk #3 07/30/94 68 108442 6160 819 21935 Atlas Resources, Inc. Kirk #2 08/03/94 68 67468 6163 493 22033 Atlas Resources, Inc. Byler #10 01/23/95 64 73357 6209 652 22269 Atlas Resources, Inc. Ealy #3 09/01/96 44 56220 5451 604 22347 Atlas Resources, Inc. Ealy Unit #5 03/03/97 38 61731 5379 1026 22465 Atlas Resources, Inc. Byler #29 03/03/98 24 47896 6071 1113 22466 Atlas Resources, Inc. Byler #31 03/12/98 25 58571 6034 2743 22472 Atlas Resources, Inc. Ellis #1 09/04/98 20 37172 6415 1243 22487 Atlas Resources, Inc. Kurtz #7 07/14/98 20 57874 6020 2248 62 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership. ID DATE MOS TOTAL TOTAL LATEST NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY CLINTON/MEDINA DEPTH PROD. ----------------------------------------------------------------------------------------------------------------------------- 22492 Atlas Resources, Inc. Byler #25 03/25/98 24 31186 5848 922 22493 Atlas Resources, Inc. Western Reserve Sports #1 03/22/98 26 11801 5756 409 22496 Atlas Resources, Inc. Byers #2 03/19/98 24 21839 5893 545 22530 Atlas Resources, Inc. Hughes #2 08/23/98 20 8830 5894 228 22538 Atlas Resources, Inc. Book #1 03/31/99 13 10078 5905 520 22539 Atlas Resources, Inc. Wengerd #3 01/12/99 16 32079 6048 1521 22554 Atlas Resources, Inc. Byler #32 08/23/98 20 42415 5941 1238 22559 Atlas Resources, Inc. Borowicz #1 09/22/98 20 26209 5955 663 22560 Atlas Resources, Inc. Thompson #9 10/22/98 18 16660 5781 790 22566 Atlas Resources, Inc. Santelli #1 10/20/99 7 12341 5882 1276 22568 Atlas Resources, Inc. Byers #3 10/19/99 7 15297 5829 1774 22570 Atlas Resources, Inc. Donner #1 10/05/98 19 37408 5902 1397 22590 Atlas Resources, Inc. Thompson #8 10/26/99 7 19663 5805 3475 22595 Atlas Resources, Inc. Thompson #7 02/19/99 15 23169 5750 1232 22610 Atlas Resources, Inc. Jovenall #1 03/02/99 14 13723 5889 639 22617 Atlas Resources, Inc. Cameron #2 03/10/99 14 13413 5843 666 22629 Atlas Resources, Inc. Dixon #4 03/16/99 14 7589 5964 546 22638 Atlas Resources, Inc. Cypher Unit #1 03/17/99 13 22438 5272 1119 22651 Atlas Resources, Inc. Byler #62 07/02/99 10 19954 5931 1627 22653 Atlas Resources, Inc. Buckwalter Unit #1 07/31/99 9 28612 5834 3454 22675 Atlas Resources, Inc. Ligo Unit #1 08/28/99 8 14419 6005 1304 22676 Atlas Resources, Inc. Byler #66 08/27/99 9 15771 5921 1202 22677 Atlas Resources, Inc. Byler #69 09/15/99 8 22775 5883 2837 22678 Atlas Resources, Inc. Hayman #1 10/11/99 7 16354 5924 1865 22680 Atlas Resources, Inc. Turner #2 09/09/99 7 14636 5271 2065 22685 Atlas Resources, Inc. Byler Unit #67 10/08/99 7 14539 5951 1325 22687 Atlas Resources, Inc. Ammann #1 09/19/99 N/A N/A 5513 N/A 22690 Atlas Resources, Inc. Living Word #1A 10/08/99 7 16953 5919 1887 22696 Atlas Resources, Inc. King #4 10/01/99 N/A N/A 5466 N/A 22703 Atlas Resources, Inc. Wallace #1 11/03/99 6 5655 5302 947 22704 Atlas Resources, Inc. Minner #5 11/07/99 6 24523 5715 3359 22705 Atlas Resources, Inc. Minner #9 11/13/99 6 10751 5784 1714 63 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership. ID DATE MOS TOTAL TOTAL LATEST NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY CLINTON/MEDINA DEPTH PROD. ----------------------------------------------------------------------------------------------------------------------------- 22706 Atlas Resources, Inc. McFarland #15 12/17/99 5 9689 5967 1777 22707 Atlas Resources, Inc. Hostetler Unit #14 12/07/99 4 8332 5952 1606 22708 Atlas Resources, Inc. Hostetler #15 12/12/99 5 14133 5930 2989 22710 Atlas Resources, Inc. Swaney #6 11/20/99 6 16013 5775 2658 22711 Atlas Resources, Inc. Swaney Unit #5 11/14/99 6 10492 5808 1507 22713 Atlas Resources, Inc. Buckwalter Unit #2 11/17/99 5 7234 5791 1197 22714 Atlas Resources, Inc. Combine #1 12/19/99 4 23334 5811 8540 22716 Atlas Resources, Inc. Yoder #8 12/14/99 5 9064 5979 1729 22717 Atlas Resources, Inc. Lehto #1 12/29/99 4 3636 5893 791 22720 Atlas Resources, Inc. Bobish #1 12/16/99 1 794 5785 N/A 22721 Atlas Resources, Inc. Czubek #2 12/29/99 4 7746 5711 2199 22731 Atlas Resources, Inc. Shaffer Unit #8 01/19/00 4 14821 5864 4534 22732 Atlas Resources, Inc. Gilliland #1 12/03/99 N/A N/A 5893 N/A 22733 Atlas Resources, Inc. Jovenall #3 12/09/99 N/A N/A 5883 N/A 22735 Atlas Resources, Inc. Horodnic #2 12/10/99 4 11462 5890 2780 22739 Atlas Resources, Inc. Leali #6 12/29/99 4 4761 5770 1393 22740 Atlas Resources, Inc. Yasnowsky #3 12/21/99 4 5387 5699 1314 22741 Atlas Resources, Inc. Minner #4 01/04/00 4 5971 5728 1537 22742 Atlas Resources, Inc. Hardisky #1 01/07/00 4 3562 5897 893 22743 Atlas Resources, Inc. Whalen #1 12/21/99 4 9116 5890 2552 22744 Atlas Resources, Inc. Picirilli #1 01/06/00 3 6423 5827 2767 22745 Atlas Resources, Inc. Minner #6 01/09/00 4 5938 5728 1440 22749 Atlas Resources, Inc. Shardy #1 01/12/00 N/A N/A 5535 N/A 22750 Atlas Resources, Inc. Leali #7 01/06/00 4 3233 5812 962 22761 Atlas Resources, Inc. Yoder #9 01/14/00 N/A N/A 5128 N/A 22763 Atlas Resources, Inc. Racketa Unit #2 01/18/00 N/A N/A 5551 N/A 22772 Atlas Resources, Inc. Herriott #1 01/24/00 3 4816 5886 2365 22774 Atlas Resources, Inc. Lehto #2 01/30/00 3 6647 5855 2615 22775 Atlas Resources, Inc. Minner #10 02/05/00 3 8145 5741 2253 22782 Atlas Resources, Inc. Garrett #2 02/21/00 1 2210 5923 N/A 22783 Atlas Resources, Inc. Yasnowsky #2 02/11/00 3 4179 5713 1294 22786 Atlas Resources, Inc. Aiken #3 02/20/00 1 1287 5629 N/A 64 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership. ID DATE MOS TOTAL TOTAL LATEST NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY CLINTON/MEDINA DEPTH PROD. ----------------------------------------------------------------------------------------------------------------------------- 22787 Atlas Resources, Inc. Garrett Unit #5 02/25/00 1 N/A 5758 N/A 22789 Atlas Resources, Inc. Byler #76 02/27/00 1 1783 5865 N/A 22790 Atlas Resources, Inc. Gearhart #1 02/21/00 1 1599 5807 N/A 22792 Atlas Resources, Inc. Minner #11 03/02/00 1 1293 5825 N/A 22793 Atlas Resources, Inc. McFarland Unit #16 02/26/00 1 1720 5861 N/A Note: Accurate through ------- Period Ending 5/2000
65 GEOLOGIC EVALUATION FOR THE CURRENTLY PROPOSED WELLS IN NORTHWESTERN PENNSYLVANIA 66 GEOLOGIC EVALUATION OF ATLAS AMERICA PUBLIC #9 LTD DRILLING PROGRAM SOUTHWESTERN MERCER & SOUTHWESTERN WARREN PROSPECT AREA PENNSYLVANIA PROGRAM PROPOSED BY: ATLAS RESOURCES, INC. 311 ROUSER ROAD P.O. BOX 611 MOON TOWNSHIP, PA 15108 REPORT SUBMITTED BY: UEDC UNITED ENERGY DEVELOPMENT CONSULTANTS, INC. 1715 CRAFTON BLVD. PITTSBURGH, PA 15205 67 [MAP]
TABLE OF CONTENTS INVESTIGATION SUMMARY..........................................................3 OBJECTIVE...............................................................3 AREA OF INVESTIGATION...................................................3 METHODOLOGY.............................................................3 PROSPECT AREA HISTORY..........................................................4 DRILLING ACTIVITY.......................................................4 GEOLOGY.................................................................4 STRATIGRAPHY, LITHOLOGY & DEPOSITION...............................4 RESERVOIR CHARACTERISTICS..........................................6 PRODUCTION CURVE........................................................8 POTENTIAL MARKETS AND PIPELINES.........................................8 STATEMENTS.....................................................................8 CONCLUSION..............................................................9 DISCLAIMER..............................................................9 NON-INTEREST............................................................9
68 INVESTIGATION SUMMARY OBJECTIVE The purpose of the following investigation is to evaluate the geologic feasibility and further development of the Southwestern Mercer & Southwestern Warren Prospect Areas (consisting of Lawrence, Mercer, Warren and Venango Counties in Pennsylvania) as proposed by Atlas Resources, Inc. AREA OF INVESTIGATION A portion of this prospect area, herein identified as the Atlas America Public #9 Ltd. Drilling Program, contains acreage in the following townships in Mercer and Lawrence Counties, located in Pennsylvania:
Mercer County Lawrence County --------------------------------------------------------- ---------------------------- Lackawannock Shenango Wilmington Wilmington East Lackawannock Sandy Creek Delaware Hickory
Thirty (30) drilling prospects designated for this program will be targeted to produce natural gas from Clinton-Medina Group reservoirs, found at an average depth range of approximately 5,100 to 6,300 feet beneath the earth's surface. These are the only prospects evaluated for the purposes of this report. Additional wells may be drilled to similar reservoirs in the following Pennsylvania counties in the townships listed below:
Crawford County Lawrence County Mercer County Warren County Venango County --------------------------------------------------------------------------------------------------- Greenfield Plain Grove Jefferson Southwest Oil Creek Oil Creek Pulaski Deer Creek Triumph Cherrytree Neshannock Eldred Cornplanter Beaver Freehold
METHODOLOGY The data incorporated into this report was provided by Atlas Resources, Inc. and the inhouse archives of UEDC, Inc. Geological mapping and the interpretations by Atlas geologists were also examined. Available "electric" log, completion, and production data on wells ofsetting prospect locations and other "key" wells within and adjacent to the defined prospect area were utilized to determine productive and depositional trends. 69 PROSPECT AREA HISTORY DRILLING ACTIVITY The proposed drilling area lies within a region of northwestern Pennsylvania which has been very active for the past decade in terms of exploration for, and exploitation of natural gas reserves. Development within and adjacent to the Southeastern Mercer Prospect Area has escalated since 1986, with Atlas Resources, Inc. and it's affiliates drilling over one thousand fifty (1050) wells during this period. Atlas Resources, Inc. has encountered favorable drilling and production results while solidifying a strong acreage position, and continues to identify and extend productive trends. Drilling is ongoing as of the date of this report with recent wells displaying favorable initial drilling and completion results. Competitive activity has begun both south and east of the prospect area, confirming the Clinton-Medina Group of Lower Silurian age as a viable target for the further development of economic quantities of natural gas. GEOLOGY STRATIGRAPHY, LITHOLOGY & DEPOSITION Regionally, the Clinton-Medina Group was deposited in tide-dominated shoreline, deltaic, and shelf environments and is lithologically comprised of alternating sandstones, siltstones and shales. Productive sandstones are composed of siliceous to dolomitic subarkoses, sublitharenites, and quartz arenites. Reservoir quality sands occur throughout the delta-complex from eastern Ohio through northwestern Pennsylvania and western New York. The Clinton-Medina Group, deposited during the Lower Silurian, overlies the Upper Ordovician age Queenston shale and is capped by the Middle Silurian Reynales Formation. This dolomitic limestone "cap" is known locally to drillers as the "Packer Shell". Stratigraphically, in descending order, the potentially productive units of the Clinton-Medina Group consist of the: 1) Thorold, 2) Grimsby, 3) Cabot Head, and 4) Whirlpool members. These stratigraphic relationships are illustrated in the following diagram: 70 STRATIGRAPHIC NAMES-NW PENNSYLVANIA [GRAPHIC] The WHIRLPOOL is a light gray quartzose sandstone to siltstone ranging in thickness from five (5) to twenty (20) feet. Average porosity values for this sand member range from five (5) to ten (10) percent regionally. Within the area of investigation, porosities in excess of twelve (12) percent occur within localized trends targeted for further development. The CABOT HEAD is a dark green to black shale, most likely of marine origin. Within the investigated area a Cabot Head sandstone has been encoutered in numerous wells. This formation has been found to contribute natural gas when reservoir characteristics, including evidence of enhanced permeability, warrant completion. This sand member is considered a secondary target. 71 The GRIMSBY is the thickest sandstone member of the Clinton-Medina Group. Sand development ranges from ten (10) to forty-five (45) feet within an interval comprised of fine to very fine, light gray to red sandstones and siltstones broken up by thin dark gray silty shale layers. Average porosity values for the Grimsby are approximately six (6) to (10) percent over the pay interval regionally. Permeability may be enhanced locally by the presence of naturally occurring micro-fractures. Future development focuses on established production trends. The THOROLD sandstone is the uppermost producing interval of the Clinton-Medina sequence. This interbedded ferric sand, silt and shale interval averages forty (40) to seventy (70) feet, from west to east in the prospect area. Where pay sand development occurs, porosities are in the typical Clinton-Medina group range of six (6) to (10) percent. Permeability may be enhanced locally by the presence of naturally occurring micro-fractures. RESERVOIR CHARACTERISTICS Petroleum reservoirs are formed by the presence of an impermeable barrier trapping natural gas of commercial quantities in a more permeable medium. In the Clinton-Medina, this occurs either stratigraphically when a permeable sand containing hydrocarbons encounters an impermeable shale or when a permeable sand changes gradually into a non-permeable sand by a cementation process known as "diagenesis". Thus, this type of trap represents cemented-in hydrocarbon accumulations. Electric well logs can be used in conjunction with production to interpret reservoir parameters. When sandstones in the Thorold, Grimsby, Cabot Head or Whirlpool develop porosity in excess of 6%, or a bulk density of 2.55 or less, the permeability of the reservoir (which ranges from less than 0.1 to greater than 0.2 mD) can become great enough to allow commercial production of natural gas. Small, naturally occurring cracks in the formation, referred to as micro-fractures, can also enhance permeability. A gamma, bulk density, density porosity and neutron log suite showing sand development in the Grimsby, Cabot Head and Whirlpool is illustrated on the following page. 72 [GRAPH] Two other phenomena detected by well logs can occur which are indicators of enhanced permeability. These indicators used to detect productive intervals are: - MUDCAKE BUILDUP ACROSS THE ZONE OF INTEREST - after loading the wellbore with brine fluid and circulating, an interval with enhanced permeability will accept fluid, filtering out the solids and leaving behind a buildup (or mudcake) on the formation wall. This is detectable with a caliper log. - INVASION PROFILE - during circulation, a brine that has a high conductivity (or low resistivity) that is accepted into the formation (as described above) will change the electrical conductivity of the reservoir rock near and around the wellbore. The resistivity will be low nearest to the wellbore and will increase away from the wellbore. A dual laterolog can be used to detect this profile created by a permeable zone - it records resistivity near the wellbore as well as deeper into the formation. A zone with enhanced permeability will show a separation between the shallow and deep laterologs, while a zone with little or no permeability would cause the two resistivity measurements to read exactly the same. An example follows: 73 [GRAPH] [GRAPH] PRODUCTION CURVE A model decline curve for the Southwestern Mercer Prospect Area was created, based on production histories from over 200 wells in the mature portion of the field. The percentage of gas recovery per year is illustrated by the diagram below: [GRAPH] POTENTIAL MARKETS AND PIPELINES In the area of this drilling program, there are a number of potential purchasers and transporters of natural gas. These include Wheatland Tube Company, Tenneco, National Fuel Supply, National Fuel Distribution and the People's Natural Gas Company. 74 STATEMENTS CONCLUSION UEDC has conducted a geologic feasability study of the ATLAS AMERICA PUBLIC #9 LTD. DRILLING PROGRAM, which will consist of developmental drilling of the Clinton-Medina Group sands in Mercer, Lawrence, Warren and Venango Counties, Pennsylvania. It is the professional opinion of UEDC that the drilling of wells within this program is supported by sufficient geologic and engineering data. DISCLAIMER For the purpose of this evaluation, UEDC did not visit any leaseholds or inspect any of the associated production equipment. Likewise, UEDC has no knowledge as to the validity of title, liabilities, or corporate matters affecting these properties. UEDC does not warrant individual well performance. NON-INTEREST We hereby confirm that UEDC is an independent consulting firm and that neither this firm or any of it's employees, contract consultants, or oficers has, or is committed to acquire any interest, directly or indirectly, in Atlas Resources, Inc.; nor is this firm, or any employee, contract consultant, or officer thereof, otherwise affiliated with Atlas Resources, Inc. We also confirm that neither the employment of, nor payment of compensation received by UEDC in connection with this report, is on a contingent basis. Respectfully submitted /s/ Isaias Ortiz UEDC, Inc. 75 MAP OF WESTERN PENNSYLVANIA AND FAYETTE COUNTY 76 [MAP OF WESTERN PENNSYLVANIA AND FAYETTE COUNTY] 77 LEASE INFORMATION 78
EFFECTIVE EXPIRATION LANDOWNER ROYALTY PROSPECT NAME COUNTY DATE* DATE* ------------------------------- --------------- --------------- ---------------- ------------------ 1. Grant #5 Fayette HBP 12.50% 2. Stiner #1 Fayette 01/21/2000 01/21/2003 12.50% 3. Keslar #4 Fayette HBP 12.50% 4. Check Unit #1 Fayette 04/15/2000 04/15/2005 12.50% 5. Bukovitz Tr. 5 #2 Fayette 08/30/1999 08/30/2002 12.50% 6. Lacava/USX #1 Fayette 03/15/1999 03/15/2001 12.50% 7. Stoken #1 Fayette HBP 12.50% 8. Bukovitz Tr. 4 #1 Fayette HBP 12.50% 9. Soberdash #1 Fayette 12/06/1999 12/12/2001 12.50% 10. Tiberi #1 Fayette 01/20/2000 01/20/2004 12.50% 11. Croushore #3 Fayette HBP 12.50% 12. Deaton #1 Fayette 02/25/2000 10/25/2001 12.50% 13. CFR/USX #3 Fayette 01/04/1999 01/04/2001 12.50% 14. S. Skovran #1 Fayette 05/18/1999 05/17/2004 12.50% 15. Bukovitz Tr. 1 #1 Fayette 08/30/1999 08/30/2002 12.50% 16. J. Riffle #1 Fayette HBP 12.50% 17. Fairbank Rod & Gun Fayette 01/31/2000 01/31/2005 12.50% Club #1 18. Trosiek #1 Fayette 01/24/2000 01/24/2002 12.50% 19. Friend Unit #1 Fayette 04/15/2000 04/15/2005 12.50% 20. Dick #1 Fayette HBP 12.50% OVERRIDING ROYALTY OVERRIDING INTEREST TO THE ROYALTY ACRES TO BE MANAGING GENERAL INTEREST TO NET REVENUE NET ACRES ASSIGNED TO PROSPECT NAME PARTNER 3RD PARTIES INTEREST PARTNERSHIP ------------------------------- -------------------- ---------------- ---------------- ---------- --------------- 1. Grant #5 0% 0% 87.50% 156.00 20 2. Stiner #1 0% 0% 87.50% 27.30 20 3. Keslar #4 0% 0% 87.50% 223.00 20 4. Check Unit #1 0% 0% 87.50% 10.00 10 5. Bukovitz Tr. 5 #2 0% 0% 87.50% 62.60 20 6. Lacava/USX #1 0% 0% 87.50% 146.96 20 7. Stoken #1 0% 0% 87.50% 247.50 20 8. Bukovitz Tr. 4 #1 0% 0% 87.50% 106.72 20 9. Soberdash #1 0% 0% 87.50% 108.05 20 10. Tiberi #1 0% 0% 87.50% 9.00 9 11. Croushore #3 0% 0% 87.50% 163.86 20 12. Deaton #1 0% 0% 87.50% 32.60 20 13. CFR/USX #3 0% 0% 87.50% 245.00 20 14. S. Skovran #1 0% 0% 87.50% 105.00 20 15. Bukovitz Tr. 1 #1 0% 0% 87.50% 90.34 20 16. J. Riffle #1 0% 0% 87.50% 37.50 20 17. Fairbank Rod & Gun 0% 0% 87.50% 240.26 20 Club #1 18. Trosiek #1 0% 0% 87.50% 12.77 12.77 19. Friend Unit #1 0% 0% 87.50% 25.50 20 20. Dick #1 0% 0% 87.50% 20.00 20
----------------------- *HBP - Held by Production 79 LOCATION AND PRODUCTION MAP 80 [MAP OF FAYETTE COUNTY AREA] 81 PRODUCTION DATA 82 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
ID DATE MOS TOTAL TOTAL LATEST NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY * DEPTH PROD. ---------------------------------------------------------------------------------------------------------------------------------- 10 Manufacturers Light & Heat Co Hogsett #9 10/21/47 N/A N/A N/A N/A 29 Carnegie Natural Gas Co H.C.Frick (Buffington) #1 09/07/44 N/A 101,000/1959 3700 N/A 30 Manufacturers Light & Heat Co Sangston #1 N/A N/A N/A 2391 N/A 41 Greensboro Gas Co Hogsett #2 01/01/22 N/A N/A 1968 N/A 50 Keystone Gas Co Mercer #1 11/07/58 N/A N/A 2180 N/A 56 Manufacturers Light & Heat Co Brown #1 05/21/45 N/A N/A 2608 N/A 57 Carnegie Natural Gas Co H.C.Frick Coke(Ralph)#2 02/05/45 N/A 105,000/1963 2595 N/A 58 Carnegie Natural Gas Co H.C.Frick Coke(Ralph)#1 07/22/44 228 86,000/1963 N/A N/A 62 Manufacturers Light & Heat Co Puritan Coke Co 08/15/45 N/A N/A 1615 N/A 63 Manufacturers Light & Heat Co Hogsett #6 02/17/45 N/A N/A 2793 N/A 66 Manufacturers Light & Heat Co Hogsett #8 05/26/47 N/A N/A 2475 N/A 71 Peoples Natural Gas Co DiCarlo #1 N/A N/A N/A 1975 N/A 73 Manufacturers Light & Heat Co S.Fayette C.&C.Co N/A N/A N/A 2655 N/A 78 Orville Eberly Herrington #1 05/12/45 N/A N/A 3494 N/A 79 Orville Eberly Old Home Fuel #1 10/29/47 N/A N/A 3451 N/A 84 Greensboro Gas Co Hogsett #5 08/30/44 N/A N/A 2128 N/A 85 Peoples Natural Gas Co Vail #2 06/20/46 N/A 171,000/1974 2790 N/A 87 Wahler & Powers Tomasek #1 03/05/48 N/A N/A 2295 N/A 88 Manufacturers Light & Heat Co Coffman #1 N/A N/A N/A 1390 N/A 107 Orville Eberly Puritan Coke Co 10/21/46 N/A N/A 2545 N/A 118 Peoples Natural Gas Co Kovach #1 12/07/43 N/A 263,000/1992 3162 N/A 119 W.Burkland Natale #1 06/19/44 N/A 267,000/1992 3101 N/A 122 Equitable Gas Co H.C. Frick (Buffington) #2 02/02/45 N/A 337,000/1995 3041 N/A 123 Carnegie Natural Gas Co H.C.Frick Coke(Footedale)#1 10/01/45 N/A 192,000/1995 3265 N/A 146 Castle Gas Co Springer #1 09/24/40 N/A 142,000/1990 2570 N/A 149 Castle Gas Co Coffman #2 10/01/24 N/A 573,000/1990 2490 N/A 165 N/A N/A N/A N/A 324,000/1990 2700 N/A 167 N/A N/A N/A N/A N/A 2382 N/A 168 Castle Gas Co T.Rider #1 01/01/42 N/A 477,000/1990 2579 N/A 184 Castle Gas Co Jacobs #5 10/01/43 N/A 93,000/1990 3024 N/A 197 W.Burkland F. Horak #1 05/29/46 N/A N/A 2394 N/A 200 W.Burkland Leslie #1 06/10/41 N/A N/A 1367 N/A
83 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
ID DATE MOS TOTAL TOTAL LATEST NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY * DEPTH PROD. ---------------------------------------------------------------------------------------------------------------------------------- 201 N/A N/A N/A N/A N/A 4353 N/A 202 N/A N/A N/A N/A N/A N/A N/A 205 W.Burkland Tomasek #1 01/07/39 N/A N/A 1361 N/A 220 W.Burkland Hibbs #1 07/01/40 N/A N/A 1299 N/A 224 W.Burkland Weirton Coal Co #1 07/25/45 N/A N/A 1906 N/A 225 W.Burkland Heller Coal Co #1 09/26/58 N/A N/A 1892 N/A 232 W.Burkland Gray #1 02/10/40 N/A N/A 2405 N/A 20059 M.C.Brumage DiCarlo #2 12/29/67 N/A N/A 3093 N/A 20102 Peoples Natural Gas Co Parshall #2 06/18/46 N/A 92,000/1969 2793 N/A 20103 Peoples Natural Gas Co J.A. Coffman #1 02/12/47 N/A 160,000/1970 N/A N/A 20114 Orville Eberly Sharpnack #1 04/10/45 N/A N/A 3300 N/A 20130 Keystone Gas Co Hecla #2 04/12/73 N/A N/A 3156 N/A 20134 Orville Eberly Puritan Coke Co #1 06/28/44 N/A N/A 2540 N/A 20136 Peoples Natural Gas Co Sisler #1(now Mcgill) 09/24/73 N/A N/A 3504 N/A 20138 Peoples Natural Gas Co Gray #1 (now Keslar) 09/10/73 N/A N/A 4513 N/A 20145 Orville Eberly Kalonsky #1 06/14/41 N/A N/A 2395 N/A 20181 W.Burkland Parshall #1 05/14/45 N/A 139,000/1980 2784 N/A 20185 W.Burkland Kalonsky #1 11/04/77 N/A N/A 4086 N/A 20192 W.Burkland Sharpnack #1 04/24/78 N/A N/A 4290 N/A 20226 Orville Eberly Puritan Coke Co #2 08/01/46 N/A N/A 2533 N/A 20249 W.Burkland Hanigosky #1 08/18/41 N/A N/A 2611 N/A 20263 Greensboro Gas Co Hicks #1 03/27/40 N/A N/A 2645 N/A 20272 Peoples Natural Gas Co Kovach #3 12/17/80 N/A N/A 3347 N/A 20290 Orville Eberly S. Wycinsky #1 11/20/81 N/A 199,000/1986 3250 N/A 20330 W.Burkland Valerio #1 03/22/41 N/A N/A 2502 N/A 20347 Peoples Natural Gas Co J. Magerko #1 07/13/44 N/A 149,000/1977 3709 N/A 20371 W.Burkland Ludi #2 08/27/83 N/A N/A 5789 N/A 20372 W.Burkland LaCava #1 09/07/83 N/A N/A 5665 N/A 20377 W.Burkland Lyons #2 01/01/83 N/A N/A 5300 N/A 20434 W.Burkland Staso #1 06/19/47 N/A 139,000/1994 2794 N/A 20723 Kriebel Gas Inc Kovach #1 03/23/94 N/A N/A 4450 N/A 20742 Kriebel Gas Inc Fairbank Rod & Gun #1 11/05/96 N/A N/A 3895 N/A
84 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
ID DATE MOS TOTAL TOTAL LATEST NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY * DEPTH PROD. --------------------------------------------------------------------------------------------------------------------------------- 20888 Atlas Leichliter/Savage #1A 01/10/97 28 46,400 4112 1,168 20890 Atlas New Salem Vol Fire Co #1 01/17/97 28 35,671 3980 754 20892 Atlas Zalac #1 11/05/97 26 24,534 4229 368 20900 Atlas McGill #2 02/16/97 28 35,145 5576 823 20903 Atlas McGill #3A 10/28/97 26 43,165 4265 894 20950 Atlas Leichliter #2 10/07/98 14 51,487 3856 3,264 20951 Atlas Zalac #3 11/23/97 26 16,438 4448 341 20954 Atlas Leichliter 1A 10/17/98 14 13,963 3184 487 20955 Atlas Zalac #2 12/06/97 26 26,647 4412 532 20958 Atlas Lambert/USX #1 12/16/97 25 28,479 4492 671 20961 Atlas Prah #1 12/30/97 24 17,715 4590 448 20962 Atlas Lavery #1 01/13/98 25 22,006 4476 231 20963 Atlas Wycinsky #1 01/21/98 25 12,291 4270 383 20971 Atlas Swetz/Densmore #1 01/28/98 23 3,611 6010 118 20979 W.Burkland Kalonsky #2 N/A N/A N/A N/A N/A 20991 Atlas DiCarlo #1 03/12/98 21 9,219 4439 241 20992 Atlas Fette/Davis/Sunyak #1 03/30/98 21 34,824 6015 1,116 20999 Atlas Skiles #1A 03/18/99 10 10,846 4164 745 21000 Atlas Edenborn/USX #1 01/13/99 11 12,555 3071 450 21001 Atlas K.Kovach #1 01/02/99 11 28,742 3951 2,013 21004 Atlas Winter #1 01/29/99 13 1,365 4110 141 21010 Atlas Tippet #1 01/20/99 11 30,155 3805 2,982 21021 Atlas Croushore #1 02/10/99 9 13,627 4009 1,175 21029 Atlas Christopher #1 10/25/98 14 3,821 4228 193 21030 Atlas Pollick #1 11/19/98 13 9,228 3450 471 21037 Atlas Lindsey #1 11/04/98 13 15,242 4227 487 21040 Atlas Howe #1 02/08/99 12 23,563 3643 2,658 21061 Atlas Jarina Unit #1 02/25/99 11 1,365 3650 129 21066 W.Burkland Parshall #1 N/A N/A N/A N/A N/A 21068 Atlas Skovran #1 02/15/99 11 44,119 4098 4,882 21069 Atlas Pike #1 02/19/99 10 961 3623 63 21073 W.Burkland Miles #1 N/A N/A N/A N/A N/A 85 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership. ID DATE MOS TOTAL TOTAL LATEST NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY * DEPTH PROD. ---------------------------------------------------------------------------------------------------------------------------------- 21074 Atlas E.Riffle #1 03/02/99 11 8,680 4060 442 21076 Atlas East Huntingdon #1 03/27/99 10 3,864 3866 243 21077 W.Burkland D'Amico #1 N/A N/A N/A 2500 N/A 21079 Atlas Craig #1 03/26/99 11 5,418 4015 656 21080 Atlas Bowers/Hogsett #2 02/24/99 10 8,238 3528 804 21083 Atlas K.Kovach #3 04/21/99 9 18,063 3979 1,656 21084 Atlas Leichliter #3 04/08/99 10 7,522 3839 512 21085 Atlas Filbert/USX #1 03/19/99 8 11,994 3927 1,215 21099 W.Burkland D'Amico #2 11/10/99 N/A N/A 2480 N/A 21104 Atlas Check #1 01/21/00 3 10,703 3888 4381 21105 Atlas K.Kovach #2A 02/03/00 3 9,387 4068 3648 21107 Atlas McGill #1 12/08/99 3 4,816 4052 1,478 21109 Atlas Pollick #2 02/11/00 2.75 3,211 3788 1,723 21110 Atlas Lee/Fette-Gipson #1 02/02/00 3 2,293 3933 706 21111 Atlas Skovran #3 12/18/99 3 41,043 4168 17,234 21112 Atlas Skovran #4 01/07/00 3 2,025 4187 635 21113 Atlas Visnich #1 01/19/00 3 15,090 3968 6011 21116 Atlas Johnston/Densmore #1 03/25/00 2.25 4,615 4270 2606 21118 Atlas Grant #1 01/14/00 3 35,438 3870 13990 21122 Atlas Bukovitz Tr-3 #1 01/28/00 3 8,393 3658 3031 21123 W.Burkland W.S. Burkland #1 N/A N/A N/A N/A N/A 21126 Atlas Edenborn/USX #2 02/09/00 2.75 290 3849 135 21127 Atlas Fette/Davis/Sunyak #2 01/27/00 2.5 2,349 3980 1014 21128 Atlas Bukovitz Tr-2 #1 02/18/00 2.5 1,788 3753 730 21130 Atlas Koenig #1 02/28/00 3 2,510 2070 128 21131 Atlas Winter #2 02/25/00 3 3,256 4082 1120 21133 Atlas P.Antram #1 02/18/00 3 2,187 4203 556 21135 Atlas Skovran #2 03/02/00 2.75 294 4062 102 21138 Atlas Keslar #1 03/08/00 3 18,750 4085 7699 21140 Atlas Skovran #5 03/13/00 2.75 1,950 4067 778 21143 Atlas Craig #2 03/19/00 N/A N/A 4090 N/A 21147 Atlas Krepps #1 04/01/00 2.25 2,518 4210 1,415 86 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership. ID DATE MOS TOTAL TOTAL LATEST NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY * DEPTH PROD. ---------------------------------------------------------------------------------------------------------------------------------- 90012 Manufacturers Light & Heat Co Hartley #1 12/31/46 N/A N/A 3237 N/A 90020 Duquesne Natural Gas Co J. Race #1 08/14/42 N/A N/A 3419 N/A 90035 Greensboro Gas Co Hanigosky #1 04/10/41 N/A N/A 2623 N/A 90036 Greensboro Gas Co Jefferis #1 06/21/43 N/A N/A 2599 N/A 90059 Greensboro Gas Co Hogsett #4 10/23/23 N/A N/A 3045 N/A 90066 Greensboro Gas Co Hogsett #1 01/01/11 N/A N/A 3117 N/A 90068 Greensboro Gas Co Christopher #1 01/15/15 N/A N/A 3100 N/A 90069 Greensboro Gas Co Christopher #2 02/13/17 N/A N/A 3065 N/A 90078 Greensboro Gas Co Jacobs #2 08/03/16 N/A N/A 1766 N/A 90100 Greensboro Gas Co Jacobs #4 05/23/17 N/A N/A 2751 N/A 90101 Greensboro Gas Co Christopher #3 02/03/23 N/A N/A 3206 N/A 90102 Greensboro Gas Co Hartley #1 02/07/24 N/A N/A 3210 N/A 90103 Greensboro Gas Co Riffle #1 01/18/24 N/A N/A 3035 N/A 90107 Greensboro Gas Co E.Christopher #1 01/01/16 N/A N/A 2864 N/A 90108 Greensboro Gas Co Brown #1 N/A N/A N/A 3273 N/A F22290 N/A Riffle #1 N/A N/A N/A N/A N/A F30027 N/A Riffle #1 N/A N/A N/A N/A N/A G675 Greensboro Gas Co M. Fleming #1 N/A N/A N/A 2410 N/A GRE1397 Castle Gas Co J. Kerr #1 10/22/18 N/A 337,000/1990 2400 N/A GRE22490 R.Burkland Luzerne #4 03/26/93 N/A N/A 2439 N/A L2373 Manufacturers Light & Heat Co H.G. Moore(Skovran) #1 06/18/19 N/A N/A 2005 N/A P17181 N/A N/A N/A N/A N/A N/A N/A P21257 C.D.White & Co Pollick #1 04/07/39 N/A N/A 2530 N/A P21283 Wahler & Powers Hicks #1 N/A N/A N/A N/A N/A P21286 Wahler & Powers Reynolds #1 N/A N/A N/A 3345 N/A P21341 Adrian et al Whitlock #1 N/A N/A N/A 1353 N/A P21706 Wahler & Powers Risko #1 N/A N/A N/A 2412 N/A P21747 N/A Lilley #1 N/A N/A N/A N/A N/A P21971 Bortz et al Hicks #1 N/A N/A N/A 2267 N/A P22120 Wahler & Powers Gray #2 N/A N/A N/A N/A N/A P22152 Geo Reynolds Reynolds #2 N/A N/A N/A 1370 N/A P22271 Jack Cornell Kosky #1 10/05/40 N/A N/A 2560 N/A
87 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
ID DATE MOS TOTAL TOTAL LATEST NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY * DEPTH PROD. ---------------------------------------------------------------------------------------------------------------------------------- P22272 Wahler & Powers Reynolds #3 N/A N/A N/A 2443 N/A P22359 Fayette County Gas Co Puritan Coke Co #2 N/A N/A N/A N/A N/A P22772 Bortz et al Pollick #2 N/A N/A N/A 2548 N/A P22938 Fayette County Gas Co A. Coffman #1 05/01/24 N/A N/A 2544 N/A P22969 Wahler & Powers Hibbs #2 N/A N/A N/A 2302 N/A P23664 Fayette County Gas Co Marciniak #1 N/A N/A N/A 2410 N/A P23900 Greensboro Gas Co Van Breman #1 N/A N/A N/A 2567 N/A P23901 Greensboro Gas Co Montgomery #1 N/A N/A N/A 2462 N/A P24149 Bortz et al Jefferies #1 N/A N/A N/A 2652 N/A P24150 Bachman & Rudert Vail #1 05/11/29 N/A N/A 2740 N/A P24154 Puritan Coal & Coke Wolf #1 N/A N/A N/A N/A N/A P24155 Fayette County Gas Co J. Hoover #1 N/A N/A N/A N/A N/A P24172 M.C.Brumage Riffle #1 N/A N/A N/A 2400 N/A P24173 M.C.Brumage Hartley #1 N/A N/A N/A N/A N/A P24174 M.C.Brumage Cameron #1 N/A N/A N/A N/A N/A P24175 N/A Thompson #1 N/A N/A N/A 2907 N/A P24464 M.C.Brumage Hartley #1 N/A N/A N/A N/A N/A P24828 Kirk Brumage LaCava #1 N/A N/A N/A 1900 N/A P25709 Bortz C.Snell #1 05/22/43 N/A N/A 2370 N/A P26065 Moore Palko #1 12/17/43 N/A N/A 2363 N/A P26092 H.K.Porter Hartley #1 01/06/44 N/A N/A N/A N/A P26456 H.K.Porter Hartley #1 04/12/44 N/A N/A 2055 N/A P26505 Orville Eberly Ross #1 05/02/44 N/A 56,000/1972 3240 N/A P26862 H.K.Porter Hecla #1 01/22/94 N/A N/A 3076 N/A P26874 J.D.Boyle Hoover #1 01/09/45 N/A N/A 1525 N/A P27813 R. Murray et al Hibbs #2 09/04/46 N/A N/A N/A N/A P27631 T.Blayho Hoover #1 04/26/46 N/A N/A 2400 N/A P27648 R.Murray et al Hibbs #1 05/19/46 N/A N/A 1913 N/A P27764 Petroleum Drilling Co Baird #1 10/11/46 N/A N/A 3195 N/A P27978 T.Blayho Noble #1 01/27/47 N/A N/A 2420 N/A P28257 Flack & Bungard Palko #1 06/12/47 N/A N/A 2408 N/A P28302 Brown Higbee E. Wendella #1 06/24/47 N/A N/A 2415 N/A
88 The Production Data provided in the table below is not intended to imply that the wells to be drilled by the partnership will have the same results, although it is an important indicator in evaluating the economic potential of any well to be drilled by the partnership.
ID DATE MOS TOTAL TOTAL LATEST NUMBER OPERATOR WELL NAME COMPLT'D ON LINE MCF LOGGERS 30 DAY * DEPTH PROD. ---------------------------------------------------------------------------------------------------------------------------------- P28303 Wahler & Powers Hicks #2 06/16/47 N/A N/A 2600 N/A P28368 Henry Johns M. Kobilack #1 09/02/47 N/A N/A 2402 N/A P28401 L.V. Simmer G.Kaufman #1 09/04/47 N/A N/A 2600 N/A P28757 Wahler & Powers Tomasek #2 03/08/48 N/A N/A 2350 N/A P28780 Wahler & Powers Tomasek #3 05/19/48 N/A N/A 2390 N/A P29132 Cunarro C. Mitchell #1 N/A N/A N/A N/A N/A P29233 Manufacturers Light & Heat Co Gray #1 07/23/23 N/A N/A 2605 N/A P29479 N/A C. Jones #1 N/A N/A N/A N/A N/A PNG3359 Peoples Natural Gas Co D.H. Sangston #1 10/26/42 N/A 53,000/1952 3814 N/A PNG3394 Peoples Natural Gas Co Parshall #1 05/05/43 N/A N/A 3551 N/A PNG3473 Peoples Natural Gas Co Byers #1 01/01/44 N/A N/A N/A N/A PNG3490 Peoples Natural Gas Co Stoken #1 01/01/44 N/A N/A N/A N/A PNG3664 Peoples Natural Gas Co McCann #1 10/28/46 N/A N/A N/A N/A PNG3491 Peoples Natural Gas Co Kovach #1 04/23/45 N/A N/A 3750 N/A PNG3671 Peoples Natural Gas Co Podolinski #1 09/27/46 N/A N/A N/A N/A PNG3672 Peoples Natural Gas Co H.Hogsett #3 12/10/46 N/A N/A 3212 N/A PNG3683 Peoples Natural Gas Co Parshall #3 02/12/47 N/A N/A 2546 N/A PNG3705 Peoples Natural Gas Co Jefferies #1 07/21/47 N/A N/A 2831 N/A PNG3724 Peoples Natural Gas Co H.Hogsett #4 08/14/47 N/A N/A 3327 N/A PNG3774 Peoples Natural Gas Co Springer #1 04/20/48 N/A N/A N/A N/A
* Cumulative production through 6/2000 unless noted; ie 1952 for PNG3359) 89 MANAGING GENERAL PARTNER'S GEOLOGIC EVALUATION FOR THE CURRENTLY PROPOSED WELLS IN FAYETTE COUNTY, PENNSYLVANIA 90 OBJECTIVE The purpose of the following investigation is to evaluate the geologic feasibility and further development of the Fayette Prospect Area as proposed by Atlas Resources, Inc. AREA OF INVESTIGATION A portion of this prospect area contains acreage in German, Luzerne, Redstone and Menallen Townships in Fayette County. Fayette County is located in Pennsylvania. Twenty (20) drilling prospects have currently been designated for this program and will be targeted to produce natural gas from Mississippian and Upper Devonian reservoirs, found at depths from 1900 feet to 4500 feet beneath the earth's surface. METHODOLOGY The data incorporated into this report were provided by Atlas Resources, Inc. Geological mapping and the interpretations by Atlas geologists were also examined. Available "electric" log, completion and production data on wells offsetting prospect locations and other "key" wells within and adjacent to the defined prospect area were utilized to determine productive and depositional trends. FAYETTE PROSPECT AREA DRILLING ACTIVITY The proposed drilling area lies within a region of southwestern Pennsylvania, which has been active for the past four years in terms of exploration for, and exploitation of natural gas reserves. Development within and adjacent to the Fayette Prospect Area has continued steadily since 1996. Over sixty (60) wells have been drilled in the area during this period. Atlas Resources, Inc. has encountered favorable drilling and production results while solidifying a strong acreage position of over 13,000 acres, as Atlas Resources, Inc. continues to identify and extend productive trends. Drilling is ongoing as of the date of this report with recent wells displaying favorable initial drilling and completion results. The area of proposed drilling is situated in a portion of Fayette County that has had established production from shallower, historic pay zones. Atlas Resources, Inc. will target deeper pay zones when locating a drill site within the "old shallow field area". Otherwise, Atlas Resources, Inc. will maintain a minimum of 1000 feet from any existing producing well in the area. GEOLOGY STRATIGRAPHY, LITHOLOGY & DEPOSITION The Mississippian reservoirs currently producing in the Fayette Prospect Area are the Burgoon Sandstone (lower Big Injun) and the 2nd Gas Sand. The Burgoon Sandstone is part of the massive Big Injun fluvial-deltaic sand system, which extends from eastern Kentucky through West Virginia into southwestern Pennsylvania. This reservoir is an historic prolific producing zone in this region, with some wells still producing long beyond fifty years. There is not much history of production from the 2nd Gas Sand in this area. The Upper Devonian reservoirs consist of three groups of sands, Upper Venango, Lower Venango and Bradford. Each of these "Groups" has multiple reservoirs making up their total rock section. The Upper Venango Group consists of the Gantz Sand and the Fiftyfoot Sand. The Lower Venango Group 91 consists of the Fifth Sand and the Bayard Sand. Depositional environments of these Upper and lower Venango Group sands are of near shore to offshore marine settings related to the last major advance of the Catskill Delta. The Bradford Group consists of the Lower Warren Sand, Upper Speechley Sand, Lower Speechley Sand, Upper Balltown Sand and the First Bradford Sand. Depositional environments of these sands are offshore marine, pro-delta and basin floor settings related to the intermediate advance of the Catskill Delta. Stratigraphically, in descending order, the potentially productive units of the Mississippian and Upper Devonian Groups are: 1) Burgoon, 2) 2nd Gas Sand, 3) Gantz, 4) Fiftyfoot, 5) Fifth, 6) Bayard, 7) L.Warren, 8) U.Speechley, 9) L.Speechley, 10) U.Balltown and 11) First Bradford Sand. These stratigraphic relationships are illustrated in the following diagram. STRATIGRAPHIC NAMES-FAYETTE COUNTY AREA [CHART] The BURGOON SANDSTONE is a fine to medium grained, medium to massively bedded, light-gray sandstone ranging in thickness from 200-250 feet. Average porosity values for this sand range from 6% to 12% regionally. It is not uncommon to encounter porosities as high as 20% and attendant large natural open flows from this sand. Tracking these high flow trends is targeted for further development. Also, this zone does produce water in certain locales within the Fayette Prospect Area. This reservoir is considered a secondary target in the high flow trend areas. The 2ND GAS SAND of this region has limited areal extent and therefore is not discussed in the literature regarding lithology, thickness etc. It can be inferred from underlying and overlying sands that it is probably a fine to very fine grained, light gray sand. Subsurface mapping indicates that the sand can achieve a thickness of twenty (20) feet. Average porosity values for this sand range from 10% to 13% 92 when this zone is present in the area. Peak porosities of 17% have been encountered within the prospect area. This reservoir is considered to be a secondary target when encountered. The GANTZ SAND is a white to light-gray, medium to coarse grained sandstone ranging in thickness from a few feet to over thirty (30) feet. Average porosity values for this sand range from 5% to 10% regionally. Within the area of investigation, porosities in excess of 13% occur within localized trends characterized by large natural open flows. These trends are targeted for future development. This reservoir is considered a primary target in the high flow trend areas. The FIFTYFOOT SAND is a white to light gray, thinly bedded, fine grained sandstone ranging in thickness from ten (10) to thirty (30) feet. Average porosity values for this sand range from 5% to 8% regionally. Within the prospect area, porosities in excess of 12% occur within localized trends targeted for future development. This sand reservoir is considered a secondary target. The FIFTH SAND is a white to light gray, very fine to fine grained sandstone ranging in thickness from a few feet to twenty (20) feet. Within the main Fifth fairway, porosity values average from 9% to 15%. This sand is considered a primary target and will be exploited in future development. The BAYARD SAND in the prospect area ranges in thickness from a few feet to more than sixty (60) feet. Average porosity values range from 5% to 12% for this fine to coarse grained sandstone. Discreet reservoirs within the sand have been identified and mapped. Gas shows in the member sandstones delineate trends within the prospect area and will be targeted for future development. This sand is considered a primary target. The LOWER WARREN SAND is a primary target in the prospect area. Average thickness for this sand ranges from zero (0) feet to over forty (40) feet. Porosities average between 8% and 12% in the area. Gas shows are commonly found in this sand, which is probably a fine-grained, well-sorted sand. This reservoir is targeted for future development. The UPPER SPEECHLEY SAND is considered a secondary target with average thickness ranging from two (2) feet to ten (10) feet over much of the prospect area. Gas shows from this sand are common throughout the area and the zone is combined with other zones when treated. The LOWER SPEECHLEY SAND is a primary target in the area with reservoir thickness ranging from zero (0) to over forty (40) feet. Average porosity values range from 5% to 12% where the sand is present. Significant natural and after treatment flows from this sand have been encountered. This sand is being targeted throughout the prospect area. The UPPER BALLTOWN SAND is currently being produced in a few wells in the prospect area. The zone is a siltstone with fracture-enhanced porosity, based on log interpretation, and has associated gas shows. This sand is considered a secondary target and is usually combined with other zones when treated. The FIRST BRADFORD SAND, like the Balltown above, is currently being produced in a few wells in the prospect area. This silty-sand does have porosity up to 10% in the area and is considered to be a secondary target when encountered. RESERVOIR CHARACTERISTICS Petroleum reservoirs are formed by the presence of an impermeable barrier trapping natural gas of commercial quantities in a more permeable medium. In the Mississippian and Upper Devonian reservoirs, this occurs either stratigraphically when a permeable sand containing hydrocarbons encounters impermeable shale or when permeable sand changes gradually into non-permeable sand by a cementation 93 process known as "diagenesis". Thus, this type of trap represents cemented-in hydrocarbon accumulations. Electric well logs can be used in conjunction with production to interpret reservoir parameters. When sandstones in the Mississippian and Upper Devonian reservoirs develop porosity in excess of 8%, or a bulk density of 2.50 or less, the permeability of the reservoir can become great enough to allow commercial production of natural gas. Small, naturally occurring cracks in the formation, referred to as micro-fractures, can also enhance permeability. A gamma, bulk density, neutron, induction and temperature log suite showing sand development in both the Mississippian and Upper Devonian reservoirs is illustrated below. [GRAPH] temp log arching to the left = gas (natural production) The temperature log shown in the illustration identifies where gas is entering the wellbore. Evidence of a temperature "kick" or cooling is also an indication of enhanced permeability and the willingness of the reservoir to produce gas. PRODUCTION EXPECTATIONS The prospect area produces from a number of reservoirs of different age and type. Each well has a unique combination of these reservoirs yielding different production declines. While we anticipate production from each reservoir to be comparable to like reservoirs historically produced throughout the Appalachian Basin, a model decline curve for this prospect area is not included due to the multiple sets of commingled reservoirs exclusively found in this area. We expect producing life of the proposed wells to range from twenty to forty years, which is similar to Atlas' existing wells in the area. This average projected producing life is taken directly from the 1999 audited report of Wright & Company, Inc. 94 POTENTIAL MARKETS AND PIPELINES In the area of the drilling program, Atlas Resources, Inc. will be transporting all the gas through Texas Eastern Transmission Co. and marketing all the gas through Northeast Ohio Gas Marketing Co. 95 COMPETITION, MARKETS AND REGULATION COMPETITION AND MARKETS There are many companies engaged in oil and gas drilling operations in the areas where the partnership is expected to conduct its activities. The industry is highly competitive in all phases, including acquiring suitable properties for drilling and the marketing of oil and gas. The partnership will compete with entities having financial resources and staffs larger than those available to the partnership. Current economic conditions indicate that the costs of exploration and development are increasing gradually. However, the oil and gas industry historically has experienced periods of rapid cost increases from time to time. There is a risk that over the term of the partnership there will be fluctuating or increasing costs in doing business. This would directly affect the managing general partner's ability to operate the partnership's wells at acceptable price levels. Oil and gas produced by the partnership's wells must be marketed in order for you to realize revenues. In recent years oil and gas prices have been volatile. Reduced oil and gas demand and/or excess oil and gas supplies will result in lower prices. The marketing of oil and gas production will be affected by numerous factors beyond the control of the partnership and which cannot be accurately predicted. These factors include, but are not limited to, the following: - the availability and proximity of adequate pipeline or other transportation facilities; - the amount of domestic production and foreign imports of oil and gas; - competition from other energy sources such as coal and nuclear energy; - local, state and federal regulations regarding production and the cost of complying with applicable environmental regulations; and - fluctuating seasonal supply and demand. For example, increased imports of oil and gas have occurred and are expected to continue. The free trade agreement between Canada and the United States has eased restrictions on imports of Canadian gas to the United States, and the North American Free Trade Agreement ("NAFTA") eliminated trade and investment barriers in the United States, Canada and Mexico. Additionally, new pipeline projects have been proposed to the Federal Energy Regulatory Commission (the "FERC") which could substantially increase the availability of Canadian gas to certain U.S. markets. These imports could have an adverse effect on both the price and volume of gas sales from the partnership's wells. Members of the Organization of Petroleum Exporting Countries ("OPEC") establish production quotas for petroleum products from time to time with the intent of decreasing, maintaining, or increasing price levels. The managing general partner is unable to predict what, if any, effect these actions will have on prices for the oil and gas sold from the partnership's wells. The accelerating deregulation of electricity transmission has caused, and will continue to cause, a coming together of the natural gas and electric industries. Because of increased competition in the electric industry, and the enforcement of stringent environmental regulations, the electric industry increased its reliance on natural gas and this demand is expected to increase through the next decade. FERC also has sought to promote greater competition in natural gas markets. Traditionally, natural gas has been sold by gas producers to pipeline companies, which then would resell the gas to end-users. FERC changed this market structure by requiring interstate pipeline companies that transport gas for others to provide transportation service to producers, distributors and all other shippers of natural gas on a "first-come, first-served" basis. This permits producers and other shippers to sell natural gas directly to end-users and local distribution companies. FERC Order 636 requires 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 gas suppliers or producers. The 96 premise behind FERC Order 636 was that the pipeline companies had an unfair advantage over other gas suppliers or producers because they could bundle their sales and transportation services together. FERC Order 636 is designed to ensure that no gas seller has a competitive advantage over another gas seller because it also provides transportation services. The effect of FERC Order No. 636 has been to restructure the natural gas industry and increase its competitiveness. From time to time a portion of the partnership's gas may be sold to local distribution companies. While in the past these purchases were generally made on the spot market, FERC Order No. 636 has made long-term market-based gas supply arrangements more important for local distribution companies than they were previously. Although the spot market is still used, it is less important as a market-based supply source and many local distribution companies are directly buying their own gas reserves in an attempt to minimize their risks and to diversify their supplies. FERC has also required pipeline companies to develop electronic bulletin boards to ensure that the gas industry is more competitive. Through electronic bulletin boards, pipeline companies provide standardized access to information concerning capacity and prices. Local distribution companies and marketers are also working to develop companies which can access and integrate all of the information available on all pipelines' electronic bulletin boards and arrange gas supplies and transportation on behalf of purchasers from large regions of the country in order to create a national market. These systems, and the development of information service companies, will allow rapid completion of natural gas sales. Gas purchased in Kansas could, for example, be used in Seattle. Although this system may initially lower prices because of increased competition, it is anticipated to increase natural gas markets and the reliability of the markets. CRUDE OIL REGULATION Oil prices are not regulated. The price of oil is subject to the following: - supply; - demand; - the gravity of the crude oil; - sulfur content differentials; and - other factors. Certain federal reporting requirements are still in effect under U. S. Department of Energy regulations. FEDERAL GAS REGULATION Governmental agencies regulate the production and transportation of natural gas. Generally, the state regulatory agency where a producing natural gas well is located supervises production activities and the transportation of natural gas sold into intrastate markets and FERC regulates the interstate transportation of natural gas. Gas prices are not regulated. The price of gas is subject to the following: - supply; - demand; - BTU content; - pressure; - location of the wells; and - other factors. 97 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." The managing general partner believes the amendments ultimately will have a beneficial effect on natural gas markets and prices. STATE REGULATIONS Oil and gas operations are regulated in Pennsylvania by the Department of Environmental Resources. Pennsylvania and any other states where the partnership's wells may be situated impose a comprehensive statutory and regulatory scheme for oil and gas operations. Among other things, these regulations involve: - new well permit and well registration requirements, procedures and fees; - minimum well spacing requirements; - restrictions on well locations and underground gas storage; - certain well site restoration, groundwater protection and safety measures; - landowner notification requirements; - certain bonding or other security measures; - 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 may create additional financial and operational burdens on oil and gas operations like those of the partnership. ENVIRONMENTAL REGULATION Various federal, state, and local laws covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the partnership's drilling and producing operations. The partnership may generally be liable for: - cleanup costs to the United States Government under the Federal Clean Water Act for oil or hazardous substance pollution; and - hazardous substance contamination under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, the Superfund. There is unlimited liability for willful negligence or misconduct and environmental cleanup costs or damages. 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 Environmental Protection Agency will require the partnership to prepare and implement spill prevention control and countermeasure plans relating to the possible discharge of oil into navigable waters. It will also require permits to authorize the discharge of pollutants into navigable waters. State and local permits or approvals will also be needed with respect to wastewater discharges and air pollutant emissions. Violations of environment-related lease conditions or environmental permits can result in substantial civil and criminal penalties as well as potential court injunctions curtailing operations. The enforcement liabilities can result from either 98 governmental or citizen prosecution. Compliance with these statutes and regulations may cause delays or increase the cost of producing the oil and gas. Because these laws and regulations are constantly being revised and changed the managing general partner is unable to predict the ultimate costs of complying with present and future environmental laws and regulations. The managing general partner is unable to obtain insurance to protect against most environmental claims. 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 oil and gas industry. The proposals involve, among other things: - limiting the disposal of waste water from wells which could make the partnership's wells uneconomical to produce; and - changes in the tax laws. 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 costs and revenues among the managing general partner and you and the other investors. A tabular summary of the following discussion appears below. COSTS 1. ORGANIZATION COSTS. Organization 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 for any organization costs that it pays in excess of 4.5% of investors' subscriptions. - Organization costs generally means all costs of organizing the offering, but excludes sales commissions and other compensation to the dealer-manager and the broker-dealers. 2. DEALER-MANAGER FEE, SALES COMMISSIONS, REIMBURSEMENT OF MARKETING EXPENSES, AND REIMBURSEMENT FOR BONA FIDE ACCOUNTABLE DUE DILIGENCE EXPENSES. The dealer-manager fee, sales commissions, and reimbursement for bona fide accountable due diligence expenses will be charged 100% to you and the other investors. The reimbursement of marketing expenses will be charged 100% to the managing general partner. 3. LEASE COSTS. The leases will be contributed to the partnership 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. 4. INTANGIBLE DRILLING COSTS. Intangible drilling costs will be allocated and charged 100% to you and the other investors. - 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 equipment costs which must be recovered through depreciation deductions. 99 Although subscription proceeds may be used to pay the costs of drilling different wells depending on when the subscriptions are received, you and the other investors will pay the same amount of the costs regardless of when you subscribe. Also, the IRS could challenge the characterization of a portion of these costs as deductible intangible drilling costs and recharacterize the costs as some other item which may be non-deductible however, this would have no effect on the allocation and payment of the costs under the partnership agreement. 5. EQUIPMENT COSTS. Equipment costs will be allocated and charged 100% 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. 6. OPERATING COSTS, DIRECT COSTS, ADMINISTRATIVE COSTS AND ALL OTHER COSTS. Operating costs, direct costs, administrative costs, and all other partnership costs not specifically allocated will be allocated and charged to the parties in the same ratio as the related production revenues are being credited. - These costs generally include all costs of partnership administration and the costs of producing and maintaining the partnership's wells. 7. THE MANAGING GENERAL PARTNER'S REQUIRED CAPITAL CONTRIBUTION. The managing general partner's aggregate capital contributions to the partnership, including its credit for the cost of the leases contributed, must not be less than 25% of all capital contributions to the partnership. The managing general partner's capital contributions must be paid at the time the costs are required to be paid by the partnership, but not later than December 31, 2001. REVENUES The revenues from all partnership wells will be commingled. Thus, regardless of when you subscribe you will share in the revenues from all wells on the same basis as the other investors in proportion to your subscription. 1. 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 to the parties in the ratio in which oil and gas production revenues of the partnership are credited as provided in 4, below. 2. INTEREST PROCEEDS. Interest earned on your subscription before the offering closes will be credited to your account and paid approximately eight weeks after the offering closes. If a subscription is refunded, then any interest allocated to the subscription will also be refunded. After the offering closes and until proceeds from the offering are invested in the partnership's oil and gas operations any interest income from temporary investments will be allocated pro rata to the investors providing the subscriptions. 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. 4. PRODUCTION REVENUES. Subject to the managing general partner's subordination obligation as described below, all other revenues of the partnership, including production revenues, will be credited as follows: - before net of tax savings payout and partnership payout you and the other investors and the managing general partner will share in partnership revenues in the same percentage as your respective capital contribution bears to the total partnership capital contributions. For example, if the managing general partner contributes 25% of the total partnership capital contributions and you and the other investors contribute 75% of the total 100 partnership capital contributions, then the managing general partner will receive 25% of the partnership revenues and you and the other investors will receive 75% of the partnership revenues. - After net of tax savings payout the managing general partner will receive an additional 6.5% of the partnership revenues, and after partnership payout the managing general partner will receive an additional 8.5% of partnership revenues for a total additional amount of 15% of partnership revenues. In the above example, after net of tax savings payout but before partnership payout the managing general partner would receive 31.5% of the partnership revenues and you and the other investors would receive 68.5% of the partnership revenues. After partnership payout the managing general partner would then receive 40% of the partnership revenues and you and the other investors would receive 60% of the partnership revenues. - Net of tax savings payout generally means the time when the cumulative credit equivalent of the partnership's deductions for intangible drilling costs and percentage depletion on your share of the partnership's income, plus the cumulative cash distributed to you and the other participants, equals 100% of the participants' aggregate capital contributions. - Partnership payout generally means the time when the partnership's cumulative cash distributions to you and the other investors equals 100% of the investors' aggregate capital contributions. SUBORDINATION OF PORTION OF MANAGING GENERAL PARTNER'S NET REVENUE SHARE Under the partnership agreement the partnership is structured to provide you with preferred cash distributions equal to a minimum of 10% of your subscription in each of the first five 12-month periods of partnership operations. To help achieve this investment feature, the managing general partner will subordinate up to 50% of its share of partnership net production revenues to your receipt of partnership cash distributions equal to 10% of your subscription in each of the first five 12-month periods of partnership operations. - Partnership net production revenues generally means the partnership's gross revenues after deducting the related operating costs, direct costs, administrative costs and all other costs not specifically allocated. The subordination will be determined beginning with the first distribution of partnership revenues 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. The specific formula is set forth in Section 5.01(b)(4)(a) of the partnership agreement. The managing general partner anticipates you will benefit from the subordination if the price of oil and gas received by the partnership and the results of the partnership's drilling activities are unable to provide the required return. However, if the wells produce small oil and gas volumes or oil and gas prices decrease, then even with subordination your cash flow may be very small and you may not receive a return of your investment. As of March 1, 2000, the managing general partner was subordinating a portion or all of its net revenues in 11 of its previous 15 limited partnerships which currently have the subordination feature in effect, and from time to time it has subordinated its partnership revenues in all of these partnerships. TABLE OF PARTICIPATION IN COSTS AND REVENUES The following table sets forth the participation in partnership costs and revenues between the managing general partner and you and the other investors after deducting from the partnership's gross revenues: - the landowner royalties; and - any other lease burdens. 101
MANAGING GENERAL PARTNER INVESTORS ------- --------- PARTNERSHIP COSTS Organization costs..................................................................100% 0% Dealer-manager fee, sales commissions, and reimbursement for bona fide accountable due diligence expenses.....................................0% 100% Reimbursement of marketing expenses.................................................100% 0% Lease costs.........................................................................100% 0% Intangible drilling costs.............................................................0% 100% Equipment costs.....................................................................100% 0% Operating costs, administrative costs, direct costs and all other costs.....................................................................(1) (1) PARTNERSHIP REVENUES Interest income......................................................................(2) (2) Equipment proceeds..................................................................100% 0% All other revenues including production revenues Before net of tax savings payout and partnership payout (3).....................(4) (4) After net of tax savings payout, but before partnership payout (3)..............(4) (4) After partnership payout........................................................(4) (4) PARTICIPATION IN DEDUCTIONS Intangible drilling costs.............................................................0% 100% Depreciation........................................................................100% 0% Percentage depletion allowance (3)...................................................(5) (5)
------------------------ (1) These costs will be charged to the parties in the same ratio as the related production revenues are being credited. (2) Interest earned on your subscription before the offering closes will be credited to your account and paid approximately eight weeks after the offering closes. After the offering closes and until proceeds from the offering are invested in the partnership's oil and gas operations any interest income from temporary investments will be allocated pro rata to the investors providing the subscriptions. All other interest income, including interest earned on the deposit of operating revenues, will be credited as oil and gas production revenues are credited. (3) These percentages may vary if a portion of the managing general partner's partnership net production revenues is subordinated. (4) Subject to the managing general partner's subordination obligation, all other revenues of the partnership, including production revenues, will be credited as follows: before net of tax savings payout and partnership payout you and the other investors and the managing general partner will share in partnership revenues in the same percentage as your respective capital contributions bears to the total partnership capital contributions. After net of tax savings payout the managing general partner will receive an additional 6.5% of the partnership revenues, and after partnership payout the managing general partner will receive an additional 8.5% of partnership revenues for a total additional amount of 15% of partnership revenues. (5) The percentage depletion allowances will be in the same percentages as the production revenues. ALLOCATION AND ADJUSTMENT AMONG INVESTORS The partnership's revenues, gains, income, costs, expenses, losses and other charges and liabilities will be charged and credited, among you and the other investors, pro rata in accordance with your respective units. These charges and credits will take into account any investor general partner's status as a defaulting investor general partner. 102 DISTRIBUTIONS The managing general partner will review your account at least quarterly to determine whether cash distributions are appropriate and the amount to be distributed, if any. The partnership will distribute funds to you and the other investors which the managing general partner does not believe are necessary to be retained by the partnership. Also, funds will not be advanced or borrowed for purposes of distributions 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. Any cash distributions from the partnership to the managing general partner will only be made in conjunction with distributions to you and the other investors and only out of funds properly allocated to the managing general partner's account. LIQUIDATION The partnership will continue in existence 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 state law. However, if the partnership terminates upon an event which causes a dissolution under state law and it is not a final terminating event, then a successor limited partnership will automatically be formed under those circumstances. Thus, only upon a final terminating event will the partnership be liquidated. A final terminating event is any of the following: - an election to terminate the partnership by the managing general partner or the affirmative vote of investors whose subscriptions equal a majority of the total subscriptions; - the termination of the partnership under Section 708(b)(1)(A) of the Internal Revenue Code; or - the partnership ceases to be going concern. Upon liquidation of the partnership you will receive your interest in the partnership. Generally, this means an undivided interest in the assets of the partnership after payments to creditors of the partnership in the ratio of the partners' capital accounts until the capital accounts of all of the partners have been reduced to zero. Thereafter, the interest in the remaining assets of the partnership will equal a partner's interest in the related revenues of the partnership. Any in-kind property distributions to you must be made to a liquidating trust or similar entity, unless you affirmatively consent to receive an in-kind property distribution after being told of the risks associated with the direct ownership or there are alternative arrangements in place which assure that you will not be responsible for the operation or disposition of the partnership properties. If the managing general partner has not received your written consent to the in-kind 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. Also, if the partnership is liquidated, the managing general partner will be repaid for any debts owed it by the partnership before there are any payments to you and the other investors. CONFLICTS OF INTEREST IN GENERAL Conflicts of interest are inherent in oil and gas 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 certain possible conflicts of interest that may arise for the managing general partner and its affiliates in the course of the partnership, and with respect to some of the conflicts of interest, but not all, certain limitations which are designed to reduce, but which will not eliminate, the conflicts. Other than these limitations the managing general partner has not established 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. 103 The following discussion is not intended to be inclusive and other transactions or dealings may arise in the future that could result in conflicts of interest for the managing general partner and its affiliates. 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 is not the result of any negotiation with any unaffiliated third party dealing at arms' length. The managing general partner will be entitled to receive compensation and reimbursement from the partnership even if the partnership's activities result in little or no profit, or a loss to you and the other investors. The managing general partner or its affiliates providing the services or equipment can be expected to profit from the transactions, and it may be in the managing general partner's best interest to enter into contracts with itself and its affiliates rather than unaffiliated parties even if the contract terms, or skill and experience, offered by the unaffiliated third parties is comparable. The partnership agreement provides that if the managing general partner and any affiliate provide services or equipment to the partnership, then the fees charged must be competitive with the fees charged by unaffiliated persons in the same geographic area engaged in similar businesses. Also, before the managing general partner and any affiliate may provide 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 oil and gas industry. If the managing general partner and any affiliate is not engaged in such a business, then the compensation must be the lesser of its cost or the competitive rate which could be obtained in the area. Any services not otherwise described in this prospectus for which the managing general partner or an affiliate is to be compensated must be: - set forth in a written contract which describes the services to be rendered and the compensation to be paid; and - cancelable without penalty upon 60 days written notice by investors whose subscriptions equal a majority of the total subscriptions. The compensation, 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 upon request. CONFLICT REGARDING THE DRILLING AND OPERATING AGREEMENT The managing general partner anticipates that all of the wells developed by the partnership will be drilled and operated pursuant to the drilling and operating agreement. The managing general partner will be required to monitor and enforce, on behalf of the partnership, its own compliance with the provisions of the drilling and operating agreement, which creates a continuing conflict of interest. CONFLICTS REGARDING SHARING OF COSTS AND REVENUES After net of tax savings payout the managing general partner will receive a percentage of revenues greater than the percentage of costs that it pays. This may create a conflict of interest between the managing general partner and you and the other investors regarding the determination of which wells will be drilled by the partnership and the profit potential associated with the wells. In addition, the allocation of all the intangible drilling costs to you and the other investors and all the equipment costs to the managing general partner creates conflicts of interest between the managing general partner and you and the other investors. 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 complete the well if there is any opportunity to recoup any of the costs. On the other hand, the managing general partner will not have paid any money before this time and it will only want to pay the equipment costs to complete the well if it is reasonably certain of recouping its money and making a profit. Based upon its past experience, however, the managing general partner anticipates that most of the partnership wells drilled to the Clinton/Medina geological 104 formation and the Mississippian/Upper Devonian Sandstone reservoirs, which will be a majority portion of the partnership's drilling activities, will be required to be completed before it can determine the well's productivity. In any event, the managing general partner will not cause any partnership 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 will 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 any administrative or judicial proceeding involving the IRS, 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, to the amount of the partnership's deduction for intangible drilling costs, which is allocated 100% to you and the other investors; - whether or not to contest a proposed adjustment by the IRS, if any, to the amount of the managing general partner's depreciation deductions, or the credit to its capital account for contributing the leases to the partnership which would decrease the managing general partner's distribution interest in the partnership; or - the managing general partner's reimbursement from the partnership of expenses incurred by it in its role as the partnership's 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 which it considers necessary for the proper management of the partnership's 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 partnerships. The managing general partner, however, has sponsored and continues to manage other partnerships, which may be concurrent. Additionally, the managing general partner and its affiliates will engage in other oil and gas activities and unrelated business activities, either for their own account or on behalf of other partnerships, joint ventures, corporations or other entities in which they have an interest. Thus, they will have conflicts of interest in allocating management time, services and other activities. 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 partnership's 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. 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 will be drilled by the managing general partner's or its affiliate's other partnerships or third-party programs 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 partnership. 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 including a year-end partnership in which affiliates of the managing general partner invest. To lessen this conflict of interest the managing general partner generally takes a similar interest in other partnerships when it serves as managing general partner and/or driller/operator. 105 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 which 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) and (5) 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 from the managing general partner and credited towards its required capital contribution 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 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. - A determination of fair market value must be supported by an appraisal from an independent expert and be maintained in the partnership's records for at least six years. (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 its other property in the same prospect. - The term "prospect" generally means an area which is believed to contain commercially productive quantities of 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; and - the drilling or spacing unit protects against drainage. The managing general partner believes that for an oil and gas prospect located in Ohio, Pennsylvania and New York on which a well will be drilled to test the Clinton/Medina geologic formation or to the Mississippian/Upper Devonian Sandstone reservoirs, 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 which have been demonstrated to be recoverable in future years with reasonable certainty under existing economic and operating conditions. Proved reserves do not 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. It is anticipated that the majority of the wells drilled by the partnership will develop either the Clinton/Medina geologic formation or the Mississippian/Upper Devonian Sandstone reservoirs. The drilling of these wells 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 in the area surrounding the currently proposed wells. To lessen this conflict of interest, for five years the managing general partner may not drill any well: - in the Clinton/Medina geologic formation within 1,650 feet of an existing partnership well in Pennsylvania or within 1,000 feet of an existing partnership well in Ohio; or - in the Mississippian/Upper Devonian Sandstone reservoirs within 1,000 feet of an existing partnership well. 106 If the partnership abandons its interest in a well, then this restriction will continue for one year following the abandonment. (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 then 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 interest; - 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 interest. For example, if the managing general partner transfers 50% of its interest in a prospect to the partnership and retains a 50% interest, then the partnership will not pay any of the costs associated with the managing general partner's retained interest as a part of the transfer. This limitation 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. For example, the managing general partner may sell its retained 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 closing, 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) NO SALE OF LEASES TO THE MANAGING GENERAL PARTNER. The managing general partner and its affiliates will not purchase any producing or non-producing oil and gas properties from the partnership. (7) NO TRANSFER OF LEASES BETWEEN AFFILIATED LIMITED PARTNERSHIPS. The partnership will not purchase properties from or sell properties to any other affiliated partnership. This prohibition, however, does not apply to joint ventures among affiliated partnerships, provided that: 107 - 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 will acquire only leases that are reasonably expected to meet the stated purposes of the partnership. No leases will be acquired for the purpose of a subsequent sale unless the acquisition is made after a well has been drilled to a depth sufficient to indicate that such an acquisition would be in the partnership's best interest. CONFLICTS BETWEEN INVESTORS AND THE MANAGING GENERAL PARTNER AS AN INVESTOR Any subscription by the managing general partner, its officers, directors, or affiliates 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. 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 the 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 which would be provided by independent underwriters. Although Anthem Securities, which is affiliated with the managing general partner, serves as dealer-manager and will receive reimbursement of accountable due diligence expenses for certain due diligence investigations conducted by the selling agents which will be reallowed to the selling agents, its due diligence examination concerning this offering cannot be considered to be independent. CONFLICTS CONCERNING LEGAL COUNSEL It is anticipated that legal counsel to the managing general partner will also serve as legal counsel to the partnership and that this dual representation will continue in the future. If a future dispute arises between the managing general partner and you and the other investors, 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 to retain separate counsel. CONFLICTS REGARDING PREPARATION OF GEOLOGICAL REPORT The geological report for Fayette County, Pennsylvania which covers a portion of the currently proposed wells was prepared by the managing general partner which is not independent. This lack of independence in the preparation of the report may affect its reliability since the managing general partner has an incentive to prepare a more positive report than an independent geologist. CONFLICTS REGARDING PRESENTMENT FEATURE You and the other investors have the right to present your units to the managing general partner for repurchase beginning in 2005. This creates the following conflicts of interest between you and the managing general partner. - If the managing general partner does not have the necessary cash flow or it cannot borrow the funds on terms which it deems reasonable, then the managing general partner may suspend the presentment feature. 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 repurchase price based upon a reserve report that it prepares and is reviewed by an independent expert. The independent expert, however, will be chosen by the managing general partner. Also, the formula for arriving at the repurchase price has subjective determinations that are within the discretion of the managing general partner. 108 CONFLICTS REGARDING MANAGING GENERAL PARTNER WITHDRAWING AN INTEREST With respect to the managing general partner's subordination obligation a conflict of interest is created with you and the other investors by the managing general partner's right to hypothecate its interest or withdraw an interest in the partnership's wells to be used as collateral for a loan. CONFLICTS REGARDING ORDER OF PIPELINE CONSTRUCTION AND GATHERING FEES A conflict of interest is created by the right of the managing general partner's parent company, Atlas America, and its affiliate, Atlas Pipeline Partners, L.P., to determine the order of priority for constructing gathering lines which may be required to connect certain of the partnership's wells into the gathering system of Atlas Pipeline Partners. Also, the managing general partner may choose well locations along the gathering system which would benefit its parent company and Atlas Pipeline Partners, even if there are well locations available in the area or other areas which offer the partnership a greater potential return. The managing general partner and its affiliates will pay the difference between the gathering fees to be paid by the partnership to Atlas Pipeline Partners, which are set forth in "Compensation - Gathering Fees," and the greater of $.35 per mcf or 16% of the gross sales price for the gas. This provides an incentive to the managing general partner to increase the amount of the gathering fees paid by the partnership in the future. 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. (1) FAIR AND REASONABLE. The managing general partner will 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. (3) FUTURE PRODUCTION. The managing general partner may not commit the future production of a partnership well exclusively for its own benefit. (4) DISCLOSURE. If an agreement or arrangement binds the partnership, then it must be fully disclosed in the prospectus. (5) NO LOANS FROM THE PARTNERSHIP. The partnership will 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 subscriptions equal a majority of the total subscriptions. (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 will be no duplication or increase in organization and offering expenses, the managing general partner's compensation, partnership expenses or other fees and costs; - there will be no substantive change in the fiduciary and contractual relationship between the managing general partner and you and the other investors; and - there will be no diminishment in your voting rights. 109 (9) INVESTMENTS. Partnership funds may not be invested in the securities of another person except in the following instances: - investments in 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 subscriptions which 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. POLICY REGARDING ROLL-UPS It is possible at some indeterminate time in the future that the partnership will 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 fundamental investment objectives of the partnership; or - materially altering the duration of the partnership. The partnership agreement provides various policies if a roll-up should occur in the future. These policies include: - an appraisal of all partnership assets must be acquired from an independent expert, and a summary of the appraisal must be included in a report to you and the other investors 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; - remaining a partner in the partnership and preserving your interests 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: - which is not approved by investors whose subscriptions equal 75% of the total subscriptions; - which would result in the diminishment of your voting rights under the roll-up entity's chartering agreement; - 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 110 - in which any of the costs of the transaction would be borne by the partnership if the proposed roll-up is not approved by investors whose subscriptions equal 75% of the total subscriptions. CERTAIN TRANSACTIONS As of April 15, 2000, previous limited partnerships sponsored by the managing general partner and its affiliates had made payments to the managing general partner and its affiliates as set forth below.
Cumulative Leasehold, Reimbursement of Drilling and Cumulative General and Investor Non-recurring Completion Operator's Administrative Partnership Subscriptions Management Fee Costs (1) Charges Overhead ----------- ------------- -------------- --------- ------- -------- Atlas L.P. #1-1985 $600,000 0 $600,000 $186,698 $42,146 A.E. Partners 1986 631,250 0 631,250 143,731 61,239 A.E. Partners 1987 721,000 0 721,000 152,876 60,028 A.E. Partners 1988 617,050 0 617,050 125,772 56,721 A.E. Partners 1989 550,000 0 550,000 109,413 55,952 A.E. Partners 1990 887,500 0 887,500 173,636 62,666 A.E. Nineties-10 2,200,000 0 2,200,000 381,327 61,771 A.E. Nineties-11 750,000 0 761,802 (2) 151,703 95,814 A.E. Partners 1991 868,750 0 867,500 144,733 80,564 A.E. Nineties-12 2,212,500 0 2,272,017 (2) 426,414 92,690 A.E. Nineties-JV 92 4,004,813 0 4,157,700 (2) 669,077 147,880 A.E. Partners 1992 600,000 0 600,000 83,879 38,925 A.E. Nineties-Public #1 2,988,960 0 3,026,348 (2) 343,493 81,997 A.E. Nineties-1993 Ltd. 3,753,937 0 3,480,656 (2) 480,719 97,494 A.E. Partners 1993 700,000 0 689,940 98,013 28,838 A.E. Nineties-Public #2 3,323,920 0 3,324,668 (2) 342,081 67,949 A.E. Nineties-14 9,940,045 0 9,512,015 (2) 1,163,337 234,054 A.E. Partners 1994 892,500 0 892,500 72,752 30,655 A.E. Nineties-Public #3 5,799,750 0 5,799,750 485,030 100,898 A.E. Nineties-15 10,954,715 0 9,859,244 (2) 937,691 198,432 A.E. Partners 1995 600,000 0 600,000 48,761 9,971 A.E. Nineties-Public #4 6,991,350 0 6,991,350 538,325 106,123 A.E. Nineties-16 10,955,465 0 10,955,465 635,890 114,198 A.E. Partners 1996 800,000 0 800,000 54,704 10,894 A.E. Nineties-Public #5 7,992,240 0 7,992,240 432,882 83,681 A.E. Nineties-17 8,813,488 0 8,813,488 378,062 75,122 A.E. Partners 1997 506,250 0 506,250 20,368 3,962 A.E. Nineties-Public #6 9,901,025 0 9,901,025 405,333 71,798 A.E. Nineties-18 11,391,673 0 11,391,673 378,742 64,229 A.E. Partners-1998 1,740,000 0 1,740,000 49,128 7,906 A.E. Nineties-Public #7 11,988,350 0 11,988,350 283,067 41,603 A.E. Nineties-19 15,720,450 0 15,720,450 100,143 17,588 A.E. Partners 1999 450,000 0 450,000 0 0 A.E. Nineties-Public #8 11,088,975 0 11,088,975 0 0
---------------------------- (1) Excluding the managing general partner's capital contributions. (2) Includes additional drilling costs paid with production revenues. 111 FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER IN GENERAL The managing general partner will manage the partnership and its assets. It is accountable to you as a fiduciary and it must exercise good faith and deal fairly with you and the other investors in conducting the affairs of the partnership. 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 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. Also, the managing general partner may not employ, or permit another to employ, the funds or assets in any manner except for the exclusive benefit of the partnership. 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 except as set forth in Sections 4.01, 4.02, 4.04, 4.05 and 4.06 of the partnership agreement. This is a rapidly expanding and changing area of the law and if you have questions concerning the duties of the managing general partner you should 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 the partnership or you and the other investors 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. Thus, you and the other investors may have a more limited right of action than you would have had without these limitations in the partnership agreement. 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 limitation 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 is contrary to public policy and therefore unenforceable. Payments arising from the indemnification or agreement to hold harmless are recoverable only out of the following: - the tangible net assets of the partnership; - revenues from operations; and - insurance proceeds. Still, use of partnership funds or assets for indemnification would reduce amounts available for partnership operations or for distribution to you and the other investors. The partnership will not pay the cost of the portion of any insurance which insures the managing general partner, the operator, or an affiliate against any liability for which they cannot be indemnified. In addition, partnership funds can be advanced to them for legal expenses and other costs incurred in any legal action for which indemnification is being sought only if the partnership has adequate funds available and certain conditions in the partnership agreement are met. 112 TAX ASPECTS SUMMARY OF TAX OPINION The managing general partner has received the tax opinion of special counsel, Kunzman & Bollinger, Inc., Oklahoma City, Oklahoma, which is included as Exhibit (8) to the registration statement. This section of the prospectus is a summary of the tax opinion and all the material federal income tax consequences of the purchase, ownership and disposition of the general and limited partner interests. You are strongly urged to read the entire tax opinion. The tax opinion represents only special counsel's best legal judgment, and has no binding effect or official status. It is only special counsel's prediction as to the outcome of the issues addressed and the results are not certain. As required by IRS regulations, special counsel's opinions state whether it is "more likely than not" that the predicted outcome will occur. There is no assurance that the present laws or regulations will not be changed and adversely affect you. Also, the IRS may challenge the deductions claimed by the partnership or you, or the taxable year in which such deductions are claimed, and no guaranty can be given that any such challenge would not be upheld if litigated. No advance ruling on any tax consequence of an investment in the partnership will be requested from the IRS. Different tax considerations than these addressed in this discussion may apply to foreign persons, corporations, partnerships, trusts and other prospective investors which are not treated as individuals for federal income tax purposes. Also, the treatment of the tax attributes of the partnership may vary among investors. Accordingly, you are urged to seek qualified, professional assistance in the preparation of your federal, state and local tax returns with specific reference to your own tax situation. In special counsel's opinion it is more likely than not that the following tax treatment will be upheld if challenged by the IRS and litigated. - PARTNERSHIP CLASSIFICATION. The partnership will be classified as a partnership for federal income tax purposes, and not as a corporation. The partnership, as such, will not pay any federal income taxes, and all items of income, gain, loss, and deduction of the partnership will be reportable by the partners in the partnership. - PASSIVE ACTIVITY CLASSIFICATION. - Generally, the passive activity limitations on losses under Section 469 of the Internal Revenue Code, more likely than not, will not be applicable to investor general partners before the conversion of investor general partner units to limited partner interests. - The partnership's oil and gas production income, together with gain, if any, from the disposition of its oil and gas properties, which is allocable to limited partners (other than converted investor general partners) who are individuals, estates, trusts, closely held corporations or personal service corporations more likely than not will be characterized as income from a passive activity which may be offset by passive activity losses. - Income or gain attributable to investments of working capital of the partnership will be characterized as portfolio income, which cannot be offset by passive activity losses. - NOT A PUBLICLY TRADED PARTNERSHIP. Assuming that no more than 10% of the units are transferred in any taxable year of the partnership, other than in private transfers described in Treas. Reg. Section 1.7704-1(e), it is more likely than not that the partnership will not be treated as a "publicly traded partnership" under the Internal Revenue Code. - AVAILABILITY OF CERTAIN DEDUCTIONS. Business expenses, including payments for personal services actually rendered in the taxable year in which accrued, which are reasonable, ordinary and necessary and do not include amounts for items such as lease acquisition costs, organization and syndication fees and other items which are required to be capitalized, are currently deductible. - INTANGIBLE DRILLING COSTS. Intangible drilling costs paid by the partnership under the terms of bona fide drilling contracts for the partnership's wells will be deductible in the taxable year in which the payments are made and the drilling services are rendered, assuming such amounts are fair and reasonable consideration and 113 subject to certain restrictions summarized below, including basis and "at risk" limitations and the passive activity loss limitation with respect to the limited partners. - PREPAYMENTS OF INTANGIBLE DRILLING COSTS. Depending primarily on when the partnership subscriptions are received, the managing general partner anticipates that the partnership will prepay in 2000 most, if not all, of the intangible drilling costs related to partnership wells the drilling of which will begin in 2001. Assuming that the amounts are fair and reasonable, and based in part on the factual assumptions set forth below, in special counsel's opinion the prepayments of intangible drilling costs will be deductible for the 2000 taxable year even though all owners in the well may not be required to prepay such amounts, subject to certain restrictions summarized below, including basis and "at risk" limitations, and the passive activity loss limitation with respect to the limited partners. The foregoing opinion is based in part on the assumptions that: - the intangible drilling costs will be required to be prepaid in 2000 for specified wells pursuant to the drilling and operating agreement; - pursuant to the drilling and operating agreement the drilling of the wells is required to be, and actually is, begun on or before March 31, 2001, and the wells are continuously drilled thereafter until completed, if warranted, or abandoned; and - the required prepayments are not refundable to the partnership and any excess prepayments are applied to intangible drilling costs of substitute wells. - DEPLETION ALLOWANCE. The greater of cost depletion or percentage depletion will be available to qualified investors as a current deduction against the partnership's oil and gas production income, subject to certain restrictions summarized below. - TAX BASIS OF INVESTOR'S INTEREST. Each investor's adjusted tax basis in his partnership interest will be increased by his total subscription. - AT RISK LIMITATION ON LOSSES. Each investor initially will be "at risk" to the full extent of his subscription. - ALLOCATIONS. Assuming the effect of the allocations of income, gain, loss and deduction (or items thereof) set forth in the partnership agreement, including the allocations of basis and amount realized with respect to oil and gas properties, is substantial in light of an investor's tax attributes that are unrelated to the partnership, it is more likely than not that such allocations will have "substantial economic effect" and will govern each investor's distributive share of such items to the extent such allocations do not cause or increase deficit balances in the investors' capital accounts. - SUBSCRIPTION. No gain or loss will be recognized by the investors on payment of their subscriptions. - PROFIT MOTIVE AND NO TAX SHELTER REGISTRATION. Based on the managing general partner's representation that the partnership will be conducted as described in the prospectus, it is more likely than not that the partnership will possess the requisite profit motive under Section 183 of the Internal Revenue Code and is not required to register with the IRS as a tax shelter. - IRS ANTI-ABUSE RULE. Based on the managing general partner's representation that the partnership will be conducted as described in the prospectus, it is more likely than not that the partnership will not be subject to the anti-abuse rule set forth in Treas. Reg. Section 1.701-2. - OVERALL EVALUATION OF TAX BENEFITS. Based on special counsel's conclusion that substantially more than half of the material tax benefits of the partnership, in terms of their financial impact on a typical investor, more likely than not will be realized if challenged by the IRS, it is the special counsel's opinion that the tax benefits of the partnership, in the aggregate, which are a significant feature of an investment in the partnership by a typical original investor more likely than not will be realized as contemplated by the prospectus. PARTNERSHIP CLASSIFICATION For federal income tax purposes, a partnership is not a taxable entity. The partners, rather than the partnership, receive any deductions and credits, as well as the income, from the operations engaged in by the partnership. A business entity with two or more members is classified for federal tax purposes as either a corporation or a partnership. Because the partnership was formed under the Pennsylvania Revised Uniform Limited Partnership Act which describes the partnership as a "partnership," it 114 will automatically be classified as a partnership unless it elects to be classified as a corporation. In this regard, the managing general partner has represented that no election for the partnership to be classified as a corporation will be filed with the IRS. LIMITATIONS ON PASSIVE ACTIVITIES Under the passive activity rules, 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. Losses generated by "passive activities" can offset only passive income and cannot be applied against active income or portfolio income. Suspended losses may be carried forward, but not back, and used to offset future years' passive activity income. 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 and generally will be subject to the passive activity limitations. Investor general partners also do not materially participate in the partnership. However, because investor general partners do not have limited liability under the Pennsylvania Revised Uniform Limited Partnership Act until they are converted to limited partners, their deductions generally will not be treated as passive deductions before the conversion. However, if an investor general partner invests in the partnership through an entity which limits his liability, for example, a limited partnership, limited liability company, or S corporation, he will be treated the same as a limited partner and generally will be subject to the passive activity limitations. Contractual limitations on the liability of investor general partners under the partnership agreement such as insurance, limited indemnification, etc. will not cause investor general partners to be subject to the passive activity limitations. PUBLICLY TRADED PARTNERSHIP RULES. Net losses of a partner from each publicly traded partnership are suspended and carried forward to be netted against income from that publicly traded partnership only. In addition, net losses from other passive activities may not be used to offset net income from a publicly traded partnership. However, in the opinion of special counsel it is more likely than not that the partnership will not be characterized as a publicly traded partnership under the Internal Revenue Code so long as no more than 10% of the Units are transferred in any taxable year of the partnership other than in private transfers described in Treas. Reg. Section 1.7704-1(e). CONVERSION FROM INVESTOR GENERAL PARTNER TO LIMITED PARTNER. Investor general partner units will be converted to limited partner interests after substantially all of the partnership wells have been drilled and completed, which the managing general partner anticipates will be in the late summer of 2001. Thereafter, each investor general partner will have limited liability as a limited partner under the Pennsylvania Revised Uniform Limited Partnership Act with respect to his interest in the partnership. Concurrently, the investor general partner will become subject to the passive activity limitations. However, his net income from the partnership's wells following the conversion will continue to be characterized as non-passive income which cannot be offset with passive losses. An investor general partner's conversion of his partnership interest into a limited partner interest should not have any other adverse tax consequences unless the investor general partner's share of any partnership liabilities is reduced as a result of the conversion. A reduction in a partner's share of liabilities is treated as a constructive distribution of cash to such partner, which reduces the basis of the partner's interest in the partnership and is taxable to the extent it exceeds his basis. TAXABLE YEAR The partnership intends to adopt a calendar year taxable year. 2000 EXPENDITURES The managing general partner anticipates that all of the partnership's subscription proceeds will be expended in 2000 and that your share of the income and deductions generated pursuant thereto will be reflected on your federal income tax return for that period. Depending primarily on when the partnership subscriptions are received, the managing general partner anticipates that the partnership will prepay in 2000 most, if not all, of its intangible drilling costs for wells the drilling of which will begin in 2001. The deductibility in 2000 of such advance payments cannot be guaranteed. 115 AVAILABILITY OF CERTAIN DEDUCTIONS Ordinary and necessary business expenses, including reasonable compensation for personal services actually rendered, are deductible in the year incurred. The managing general partner has represented to special counsel that the amounts payable to the managing general partner and its affiliates, including the amounts paid to the managing general partner or its affiliates as general drilling contractor, are the amounts which would ordinarily be paid for similar services in similar transactions. The fees paid to the managing general partner and its affiliates will not be currently deductible if: - they are in excess of reasonable compensation; or - they are properly characterized as organization or syndication fees, other capital costs such as the acquisition cost of the leases, or are not "ordinary and necessary" business expenses. In the event of an audit, payments to the managing general partner and its affiliates by the partnership will be scrutinized by the IRS to a greater extent than payments to an unrelated party. INTANGIBLE DRILLING COSTS Assuming a proper election and subject to the passive activity loss rules in the case of limited partners, you will be entitled to deduct your share of intangible drilling costs which include items which do not have salvage value, such as labor, fuel, repairs, supplies and hauling necessary to the drilling of a well. Intangible drilling costs generally will be treated as ordinary income if a property is sold at a gain. Also, productive-well intangible drilling costs may subject you to an alternative minimum tax in excess of regular tax unless an election is made to deduct them on a straight line basis over a 60-month period. Under the partnership agreement 90% of the subscription proceeds received by the partnership from you and the other investors will be used to pay intangible drilling costs which are charged 100% to you and the other investors. The IRS could challenge the characterization of a portion of these costs as deductible intangible drilling costs and recharacterize the costs as some other item which may be non-deductible; however, this would have no effect on the allocation and payment of the costs under the partnership agreement. The amount of the deduction for intangible drilling costs is limited for integrated oil companies. Integrated oil companies are: - those taxpayers who directly or through a related person engage in the retail sale of oil or gas and whose gross receipts for the calendar year from such activities exceed $5 million; or - those taxpayers and related persons who have refinery production in excess of 50,000 barrels on any day during the taxable year. DRILLING CONTRACTS The partnership will enter into the drilling and operating agreement with the managing general partner or its affiliates, as a third-party general drilling contractor, to drill and complete the partnership's development wells on a cost plus 15% basis. For its services as general drilling contractor, the managing general partner anticipates that on average over all of the wells drilled and completed by the partnership it will have reimbursement of general and administrative overhead of approximately $12,900 per well and a profit of 15% (approximately $21,850) per well with respect to the intangible drilling costs paid by you and the other investors as described in "Compensation - Drilling Contracts". However, the actual cost of drilling and completing the wells may be more or less than the estimated amount, due primarily to the uncertain nature of drilling operations, and the managing general partner's reimbursement of overhead and profit also could be more or less than the amount estimated by the managing general partner. The managing general partner believes the drilling and operating agreement is at a competitive rate in the proposed areas of operation. Nevertheless, the amount of the profit realized by the managing general partner under the drilling and operating agreement could be challenged by the IRS as unreasonable and disallowed as a deductible intangible drilling cost. Depending primarily on when the partnership subscriptions are received, the managing general partner anticipates that the partnership will prepay in 2000 most, if not all, of the intangible drilling costs for drilling activities that will begin in 2001. 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 costs. First, the expenditure must be a payment rather than a refundable deposit. Second, the deduction must not result in a material distortion of income taking into substantial consideration the business purpose aspects of the transaction. 116 The partnership will attempt to comply with the guidelines set forth in KELLER with respect to prepaid intangible drilling costs. The drilling and operating agreement will require the partnership to prepay in 2000 intangible drilling costs for specified wells the drilling of which will begin in 2001. Prepayments should not result in a loss of current deductibility where there is a legitimate business purpose for the required prepayment, the contract is not merely a sham to control the timing of the deduction and there is an enforceable contract of economic substance. The drilling and operating agreement will require the partnership to prepay the intangible drilling costs of drilling and completing the wells in order to enable the operator to commence 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 amounts, if any, will not be refundable to the partnership but will be applied to intangible drilling costs to be incurred in drilling and completing substitute wells. Under KELLER, such a provision for substitute wells should not result in the prepayments being characterized as refundable deposits. The likelihood that prepayments will be challenged by the IRS on the grounds that there is no business purpose for the prepayment is increased in the event prepayments are not required with respect to the entire well. It is possible that less than 100% of the interest will be acquired by the partnership in one or more wells and prepayments may not be required of all owners of interests in the wells. However, in the view of special counsel, a legitimate business purpose for the required prepayments may exist under the guidelines set forth in KELLER, even though prepayment is not required, or actually received, by the drilling contractor with respect to a portion of the interest in the wells. In addition to the foregoing, 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. The managing general partner will attempt to cause the drilling of all prepaid partnership wells to begin on or before March 31, 2001. However, the drilling of any partnership well may be delayed due to circumstances beyond the control of the partnership or the drilling contractor. Such circumstances include, for example, the unavailability of drilling rigs, decisions of third-party operators to delay drilling the wells, weather conditions, inability to obtain drilling permits or access right to the drilling site, or title problems. Due to the foregoing factors no guaranty can be given that the drilling of all prepaid partnership wells required by the drilling and operating agreement to begin on or before March 31, 2001, will actually begin by that date. In that event, deductions claimed in 2000 for prepaid intangible drilling costs would be disallowed and deferred to the 2001 taxable year. No assurance can be given that on audit the IRS would not disallow the current deductibility of a portion or all of any prepayments of intangible drilling costs under the partnership's drilling contracts, thereby decreasing the amount of deductions allocable to the investors for the current taxable year, or that such a challenge would not ultimately be sustained. In the event of disallowance, the deduction would be available in the year the work is actually performed. DEPLETION ALLOWANCE Proceeds from the sale of the partnership's oil and gas production will constitute ordinary income. A certain portion of the income will not be taxable by virtue of 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. Depletion deductions generally will be treated as ordinary income if a property is sold at a gain. Cost depletion for any year is determined by dividing the adjusted tax basis for the property by the total units of gas or oil expected to be recoverable therefrom 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 generally is available to taxpayers other than integrated oil companies. Percentage depletion is based on your share of the partnership's gross production income from its oil and gas properties. The rate of percentage depletion is 15%. However, 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. The term "marginal production" includes oil and gas produced from a domestic stripper well property, which is defined as any property which produces a daily average of 15 or less equivalent barrels of oil, which is 90 MCF of natural gas, per producing well on the property in the calendar year. The rate of percentage depletion for marginal production in 2000 is 24%. This rate fluctuates from year to year depending on the price of oil, but will not be less than the statutory rate of 15% nor more than 25%. 117 Also, percentage depletion: - may not exceed 100% of the net income from each oil and gas property before the deduction for depletion; and - is limited to 65% of the taxpayer's taxable income for a year computed without regard to deductions for percentage depletion, net operating loss carry-backs and capital loss carry-backs. With respect to marginal properties, however, the 100% of net income property limitation is suspended for 2000 and 2001. AVAILABILITY OF PERCENTAGE DEPLETION MUST BE COMPUTED SEPARATELY BY YOU, AND NOT BY THE PARTNERSHIP OR FOR INVESTORS AS A WHOLE. YOU ARE URGED TO CONSULT YOUR OWN TAX ADVISORS WITH RESPECT TO THE AVAILABILITY OF PERCENTAGE DEPLETION TO YOU. DEPRECIATION - MODIFIED ACCELERATED COST RECOVERY SYSTEM ("MACRS") Equipment costs to drill and complete the partnership's wells, and the related depreciation deductions, are allocated and charged under the partnership agreement 100% to the managing general partner. LEASEHOLD COSTS AND ABANDONMENT The costs of acquiring oil and gas lease interests, together with the related cost depletion deduction and any abandonment loss, 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 INVESTORS' INTERESTS Your distributive share of partnership loss is allowable only to the extent of the adjusted basis of your interest in the partnership at the end of the partnership's taxable year. The adjusted basis for federal income tax purposes of your interest in the partnership will be adjusted, but not below zero, for any gain or loss to you from a disposition by the partnership of an oil or gas property, and will be increased by your: - cash subscription payment; - share of partnership income; and - share, if any, of partnership debt. The adjusted basis of your interest in the partnership will be reduced by your: - share of partnership losses; - depletion deduction, but not below zero; and - cash distributions from the partnership. The reduction in your share of partnership liabilities, if any, is considered a cash distribution. Should cash distributions exceed the tax basis of your interest in the partnership, taxable gain would result to the extent of the excess. "AT RISK" LIMITATION FOR LOSSES Subject to the limitations on "passive losses" generated by the partnership in the case of limited partners and your basis in the partnership, you may use your share of the partnership's losses to offset income from other sources. However, you may deduct the loss only to the extent of the amount you have "at risk" in the partnership at the end of a taxable year. Your initial amount "at risk" is the amount of money you have contributed to the partnership. However, the amount you have "at risk" may not include the amount of any loss that you are protected against through: - nonrecourse loans; - guarantees; - stop loss agreements; or - other similar arrangements. 118 DISTRIBUTIONS FROM A PARTNERSHIP Generally, a cash distribution from a partnership to a partner in excess of the adjusted basis of the partner's interest in the partnership immediately before the distribution is treated as gain from the sale or exchange of his interest in the partnership to the extent of the excess. No loss is recognized by the partners on these types of distributions. Other distributions of cash, disproportionate distributions of property, and liquidating distributions may result in taxable gain or loss. SALE OF THE PROPERTIES Generally, net long-term capital gains of a noncorporate taxpayer on the sale of assets held more than a year are taxed at a maximum rate of 20%, or 10% if they would be subject to tax at a rate of 15% if they were not eligible for long-term capital gains treatment. These rates also apply for purposes of the alternative minimum tax. 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. Gains or losses from sales of oil and gas properties held for more than twelve months generally will be treated as a long-term capital gain, while a net loss will be an ordinary deduction. However, on disposition of an oil and gas property gain is treated as ordinary income to the extent of the lesser of: - the amounts that were deducted as intangible drilling costs rather than added to basis, plus depletion deductions that reduced the basis of the property and certain losses, if any, on previous sales of partnership assets; or - the amount realized in the case of a sale, exchange or involuntary conversion or fair market value in all other cases, minus the property's adjusted basis. Other gains and losses on sales of oil and gas properties will generally result in ordinary gains or losses. DISPOSITION OF PARTNERSHIP INTERESTS The sale or exchange, including a repurchase by the managing general partner, of all or part of your interest in the partnership held by you for more than 12 months will generally result in a recognition of long-term capital gain or loss. However, the recapturable portions of depletion and intangible drilling costs will constitute ordinary income. If the interest is held for 12 months or less, then the gain or loss will generally 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 must be included in the amount realized. Therefore, the gain recognized may result in a tax liability greater than the cash proceeds, if any, from such disposition. In addition to gain from a passive activity, a portion of any gain recognized by a limited partner on the sale or other disposition of his interest in the partnership may be characterized as portfolio income. A gift of your interest in the partnership may result in federal and/or state income tax and gift tax liability to you, and interests in different partnerships do not qualify for tax-free like-kind exchanges. Other dispositions of your interest, may or may not result in recognition of taxable gain. However, no gain should be recognized by an investor general partner whose interest in the partnership is converted to a limited partner interest so long as there is no change in his share of the partnership's liabilities or certain partnership assets as a result of the conversion. In addition, if you sell or exchange all or part of your interest in the partnership you are required by the Internal Revenue Code to notify the partnership within 30 days or by January 15 of the following year, if earlier. NO DISPOSITION OF YOUR INTEREST IN THE PARTNERSHIP, INCLUDING REPURCHASE OF THE INTEREST BY THE MANAGING GENERAL PARTNER, SHOULD BE MADE BY YOU BEFORE CONSULTATION WITH YOUR TAX ADVISOR. MINIMUM TAX - TAX PREFERENCES With limited exceptions, all taxpayers are subject to the alternative minimum tax. If your alternative minimum tax exceeds the regular tax, then the excess is payable in addition to the regular tax. The alternative minimum tax is intended to insure that no one with substantial income can avoid tax liability by using deductions and credits. The alternative minimum tax accomplishes this objective by not treating favorably certain items that are treated favorably for purposes of the regular tax, including the deduction for intangible drilling costs. Generally, the alternative minimum tax rate for individuals is 26% on alternative minimum taxable income up to $175,000, $87,500 for married individuals filing separate returns, and 28% thereafter. The regular tax rates on capital gains also apply for purposes of the alternative minimum tax. Regular tax personal exemptions are 119 not available for purposes of the alternative minimum tax, however, alternative minimum taxable income may be reduced by certain itemized deductions, exemption amounts and net operating losses. For taxpayers other than integrated oil companies, the 1992 National Energy Bill repealed the preference for: - excess intangible drilling costs; and - the excess percentage depletion preference for oil and gas. The repeal of the excess intangible drilling costs preference, however, may not result in more than a 40% reduction in the amount of the taxpayer's alternative minimum taxable income computed as if the excess intangible drilling costs preference had not been repealed. Under the prior rules, the amount of intangible drilling costs which is not deductible for alternative minimum tax purposes is the excess of the "excess intangible drilling costs" over 65% of net income from oil and gas properties. 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. THE LIKELIHOOD OF YOU INCURRING, OR INCREASING, ANY MINIMUM TAX LIABILITY BY VIRTUE OF AN INVESTMENT IN THE PARTNERSHIP MUST BE DETERMINED ON AN INDIVIDUAL BASIS, AND REQUIRES YOU TO CONSULT WITH YOUR PERSONAL TAX ADVISOR. LIMITATIONS ON DEDUCTION OF INVESTMENT INTEREST Investment interest is deductible by a noncorporate taxpayer only to the extent of net investment income each year, with an indefinite carryforward of disallowed investment interest. An investor general partner's share of any interest expense incurred by the partnership will be subject to the investment interest limitation. In addition, an investor general partner's income and losses, including intangible drilling costs, from the partnership will be considered investment income and losses. Losses allocable to an investor general partner will reduce his net investment income and may affect the deductibility of his investment interest expense, if any. These rules do not apply to partnership income or expense subject to the passive activity loss limitations for limited partners. ALLOCATIONS The partnership agreement allocates to you your share of the partnership's income, gains, and deductions, including the deduction for intangible drilling costs. Your capital account will be adjusted to reflect these allocations and your capital account, as adjusted, will be given effect in distributions made to you upon liquidation of the partnership or your interest in the partnership. Generally, your capital account will be: - increased by the amount of money you contribute to the partnership and allocations to you of income and gain; and - decreased by the value of property or cash distributed to you and allocations to you of loss and deductions. It should be noted that your share of partnership items of income, gain, loss, and deduction must be taken into account whether or not there is any distributable cash. Your share of partnership revenues applied to the repayment of loans or the reserve for plugging wells, for example, will be included in your gross income in a manner analogous to an actual distribution of the income to you. Thus, you may have tax liability from the 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 distributions will not be less than the managing general partner's estimate of the investors' income tax liability with respect to partnership income. If any allocation under the partnership agreement is not recognized for federal income tax purposes, your distributive share of the items subject to that allocation generally will be determined in accordance with your interest in the partnership, determined by considering relevant facts and circumstances. To the extent the deductions, as allocated by the partnership agreement, exceed deductions which would be allowed pursuant to such a reallocation you may incur a greater tax burden. 120 PARTNERSHIP BORROWINGS Under the partnership agreement, the managing general partner and its affiliates may make loans to the partnership. The use of partnership revenues taxable to you to repay partnership borrowings 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 as capital contributions in light of all the surrounding facts and circumstances. PARTNERSHIP ORGANIZATION AND SYNDICATION FEES Expenses connected with the sale of interests in a partnership, including the dealer-manager fee, sales commissions, and reimbursement for bona fide accountable due diligence expenses which are charged 100% to you and the other investors under the partnership agreement, are not deductible. Although certain organization expenses of the partnership may be amortized over a period of not less than 60 months, these expenses are paid by the managing general partner as part of the partnership's organization costs and any related deductions, which the managing general partner does not expect will be material in amount, will be allocated to the managing general partner. TAX ELECTIONS The partnership may elect to adjust the basis of partnership property on the transfer of an interest in a partnership by sale or exchange or on the death of a partner, and on the distribution of property by the partnership to a partner. The general effect of this election is that transferees of the partnership interests 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, upon certain distributions to partners, as though it had newly acquired an interest in the partnership assets and therefore acquired a new cost basis for the assets. Also, certain "start-up expenditures" must be capitalized and can only be amortized over a 60-month period. If it is ultimately determined that any of the partnership's expenses constituted start-up expenditures and not deductible business expenses, the partnership's deductions would be deferred. DISALLOWANCE OF DEDUCTIONS UNDER SECTION 183 OF THE INTERNAL REVENUE CODE Your ability to deduct your share of the partnership's losses could be lost if the partnership lacks the appropriate profit motive. There is 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 the partnership fails to show a profit in at least three 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 to be sufficient grounds for the denial of losses. Based on the managing general partner's representation that the partnership will be conducted as described in this prospectus, in the opinion of special counsel it is more likely than not that the partnership will possess the requisite profit motive. TERMINATION OF A PARTNERSHIP The partnership will be considered as terminated for federal income tax purposes if within a twelve month period there is a sale or exchange of 50% or more of the total interest in partnership capital and profits. In that event, you would realize taxable gain on a termination of the partnership to the extent that money regarded as distributed to you exceeds the adjusted basis of your partnership interest. The conversion of investor general partner units to limited partner interests, however, will not result in a termination of the partnership. LACK OF REGISTRATION AS A TAX SHELTER An organizer of a "tax shelter" must obtain an identification number which must be included on the tax returns of investors in the tax shelter. For this purpose, a "tax shelter" includes investments with respect to which any person could reasonably infer that the ratio that the aggregate amount of the potentially allowable deductions and 350% of the potentially allowable credits with respect to the investment during the first five years of the investment bears to the amount of money and the adjusted basis of property contributed to the investment exceeds 2 to 1, determined without reduction for gross income derived from the investment. The managing general partner does not believe that the partnership will have a tax shelter ratio greater than 2 to 1. Also, because the purpose of the partnership is to locate, produce and market natural gas on an economic basis, the managing general partner does not believe that the partnership will be a "potentially abusive tax shelter." Accordingly, the managing general partner does not intend to cause the partnership to register with the IRS as a tax shelter. 121 If it is subsequently determined by the IRS or the courts that the partnership was required to be registered with the IRS as a tax shelter, the managing general partner would be subject to certain penalties and you would be liable for a $250 penalty for failure to include the tax shelter registration number on your tax return, unless the failure was due to reasonable cause. You also would be liable for a penalty of $100 for failing to furnish the tax shelter registration number to any transferee of your interest in the partnership. However, based on the representations of the managing general partner, special counsel has expressed the opinion that the partnership, more likely than not, is not required to register with the IRS as a tax shelter. Issuance of a registration number does not indicate that an investment or the claimed tax benefits have been reviewed, examined, or approved by the IRS. INVESTOR LISTS. Any person who organizes a tax shelter required to be registered with the IRS must maintain a list of each investor in the tax shelter. For the reasons described above, the managing general partner does not believe the partnership is a tax shelter for this purpose. If this determination is wrong there is a penalty of $50 for each person, unless the failure is due to reasonable cause. TAX RETURNS AND AUDITS IN GENERAL. The tax treatment of all partnership items is generally determined at the partnership, rather than the partner, level; and the partners are generally required to treat partnership items on their individual returns in a manner which is consistent with the treatment of the partnership items on the partnership return. Generally, the IRS must conduct an administrative determination as to partnership items at the partnership level before conducting deficiency proceedings against a partner, and the partners must file a request for an administrative determination before filing suit for any credit or refund. The period for assessing tax against a partner attributable to a partnership item may be extended as to all partners by agreement between the IRS and the managing general partner, which will serve as the partnership's representative in all administrative and judicial proceedings conducted at the partnership level. The managing general partner generally may enter into a settlement on behalf of, and binding upon, partners owning less than a 1% profits interest if the partnership has more than 100 partners. 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." These rules also facilitate the matching of partnership items with individual partner tax returns by the IRS. The managing general partner does not anticipate that the partnership will make this election. By executing the partnership agreement, you 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 managing general partner does not have binding settlement authority. TAX RETURNS. Your income tax returns are your responsibility. The partnership will provide you with the tax information applicable to your investment in the partnership necessary to prepare your returns. PENALTIES AND INTEREST IN GENERAL. Interest is charged on underpayments of tax and various civil and criminal penalties are included in the Internal Revenue Code. PENALTY FOR NEGLIGENCE OR DISREGARD OF RULES OR REGULATIONS. If any portion of an underpayment of tax is attributable to negligence or disregard of rules or regulations, 20% of that portion is added to the tax. Negligence is strongly indicated if a partner fails to treat partnership items on his tax return in a manner that is consistent with the treatment of those items on the partnership's return or to notify the IRS of the inconsistency. VALUATION MISSTATEMENT PENALTY. There is an addition to tax of 20% of the amount of any underpayment of tax of $5,000 or more which is attributable to a substantial valuation misstatement. There is a substantial valuation misstatement if: - the value or adjusted basis of any property claimed on a return is 200% or more of the correct amount; or - the price for any property or services, or for the use of property, claimed on a return is 200% or more, or 50% or less, of the correct price. If there is a gross valuation misstatement, which is 400% or more of the correct value or adjusted basis or the undervaluation is 25% or less of the correct amount, then the penalty is 40%. 122 SUBSTANTIAL UNDERSTATEMENT PENALTY. There is also an addition to tax of 20% of any underpayment if the difference between the tax required to be shown on the return over the tax actually shown on the return, exceeds the greater of: - 10% of the tax required to be shown on the return; or - $5,000. The amount of any understatement generally will be reduced to the extent it is attributable to the tax treatment of an item: - supported by substantial authority; or - adequately disclosed on the taxpayer's return and there is a reasonable basis for the tax treatment of the item by the taxpayer. However, in the case of "tax shelters," the understatement may be reduced only if the tax treatment of an item attributable to a tax shelter was supported by substantial authority and the taxpayer established that he reasonably believed that the tax treatment claimed was more likely than not the proper treatment. - A "tax shelter" for this purpose is any entity which has as a significant purpose the avoidance or evasion of federal income tax. IRS ANTI-ABUSE RULE. If a principal purpose of a 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 Internal Revenue Code, based on all the facts and circumstances, the IRS is authorized to remedy the abuse. Based on the managing general partner's representation that the partnership will be conducted as described in this prospectus, in the opinion of special counsel it is more likely than not that the partnership will not be subject to this rule. STATE AND LOCAL TAXES Under Pennsylvania law, the partnership is required to withhold state income tax at the rate of 2.8% of partnership income allocable to investors who are not residents of Pennsylvania. Also, the partnership will operate in states and localities which impose a tax on its assets or its income, or on you. Deductions which are available to you for federal income tax purposes may not be available for state or local income tax purposes. YOU SHOULD CONSULT WITH YOUR OWN TAX ADVISORS CONCERNING THE POSSIBLE EFFECT OF VARIOUS STATE AND LOCAL TAXES ON YOUR PERSONAL TAX SITUATION. SEVERANCE AND AD VALOREM (REAL ESTATE) TAXES The partnership may incur various ad valorem or severance taxes imposed by state or local taxing authorities. Currently, there is no such tax liability in Mercer County, Pennsylvania. 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. For 2000 the ceiling for social security tax of 12.4% is $76,200 and there is no ceiling for medicare tax of 2.9%. Self-employed individuals can deduct one-half of their self-employment tax. FOREIGN PARTNERS The partnership will be required to withhold and pay to the IRS tax at the highest rate under the Internal Revenue Code applicable to partnership income allocable to foreign partners, even if no cash distributions are made to such partners. In the event of overwithholding, a foreign partner must file a United States tax return to obtain a refund. 123 ESTATE AND GIFT TAXATION There is no federal tax on lifetime or testamentary transfers of property between spouses. The gift tax annual exclusion is $10,000 per donee, which will be adjusted for inflation. Estates of $675,000, which increases in stages to $1,000,000 by 2006, or less generally are not subject to federal estate tax. SUMMARY OF PARTNERSHIP AGREEMENT NOTE: THE RIGHTS AND OBLIGATIONS OF THE MANAGING GENERAL PARTNER AND YOU AND THE OTHER INVESTORS ARE GOVERNED BY THE PARTNERSHIP AGREEMENT, A COPY OF WHICH IS ATTACHED AS EXHIBIT (A) TO THIS PROSPECTUS. YOU SHOULD NOT INVEST IN THE PARTNERSHIP WITHOUT FIRST THOROUGHLY REVIEWING THE PARTNERSHIP AGREEMENT. THE FOLLOWING IS A SUMMARY OF THE MATERIAL PROVISIONS IN THE PARTNERSHIP AGREEMENT WHICH ARE NOT COVERED ELSEWHERE IN THIS PROSPECTUS. LIABILITY OF LIMITED PARTNERS The partnership will be governed by the Pennsylvania 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 the partnership. However, there are the following exceptions: - if you also invest as an investor general partner; - if you take part in the control of the business of the partnership in addition to the exercise of your rights and powers as a limited partner; - if you fail to make a required capital contribution to the extent of the required capital contribution; or - for a period of two years, any capital contributions "wrongfully" returned to you in violation of the partnership agreement or Pennsylvania law to the extent of the capital contribution wrongfully returned to you, with interest thereon. This includes, but is not limited to, any distribution to you and the other limited partners to the extent that, after giving effect to the distribution, all liabilities of the partnership exceed partnership assets. AMENDMENTS Amendments to the partnership agreement may be: - proposed in writing by the managing general partner and adopted with the consent of investors whose subscriptions equal a majority of the total subscriptions; or - proposed in writing by investors whose subscriptions equal 10% or more of the total subscriptions and adopted by an affirmative vote of investors whose subscriptions equal a majority of the total subscriptions. The partnership agreement may also be amended by the managing general partner for certain purposes. However, no amendment materially and adversely affecting the investors can be made without the consent of the affected 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 not received; - the notice periods are frequently quite short, a minimum of 22 calendar days, and apply to matters which may seriously affect your rights; and 124 - 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 Generally, you will not be entitled to vote with respect to any partnership matters at any meeting which is called by the managing general partner other than as set forth below. However, at any time upon the request of investors whose subscriptions equal 10% or more of the total subscriptions, you and the other investors 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. For each unit you own you are entitled to one vote on the matters being voted upon. However, if you own a fractional unit, then you are entitled to vote that fraction of one vote equal to the fractional interest in the unit. Investors whose subscriptions equal a majority of the total subscriptions may vote to: - 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 assets of the partnership; - cancel any contract for services with the managing general partner, the operator or their affiliates without penalty upon 60 days notice; and - amend the partnership agreement; provided however, any amendment may not: - increase the duties or liabilities of you or the managing general partner or increase or decrease the profit or loss sharing or required capital contribution of you or the managing general partner without the approval of you or the managing general partner; or - affect the classification of partnership income and loss for federal income tax purposes without the unanimous approval of all investors. The managing general partner, its officers, directors, and affiliates may also subscribe for units in the partnership on the same basis as you and the other investors, and they may vote on all matters other than: - the issues set forth in removing the managing general partner and operator above; 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 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. ACCESS TO RECORDS Generally, as a participant you will have access to all records of the partnership after notice, and at a reasonable time. However, logs, well reports and other drilling and operating data may be kept confidential for reasonable periods of time. Your ability to obtain the list of investors is subject to additional requirements set forth in the partnership agreement. 125 WITHDRAWAL OF MANAGING GENERAL PARTNER After 10 years, the managing general partner may voluntarily withdraw as managing general partner for whatever reason by giving 120 days' written notice to you and the other investors. 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 subscriptions equal a majority of the total subscriptions. If the managing general partner would withdraw and the investors failed to elect to continue the partnership and to designate a substitute managing general partner, then the partnership would terminate and dissolve. This could result in adverse tax and other consequences. Also, subject to a required participation of not less than 1% of the partnership revenues, the managing general partner may partially withdraw a property interest in the partnership's wells equal to or less than its revenue interest if the withdrawal is: - to satisfy the bona fide request of its creditors; or - approved by investors whose subscriptions equal a majority of the total subscriptions. SUMMARY OF DRILLING AND OPERATING AGREEMENT The managing general partner will serve as the operator pursuant to the drilling and operating agreement, Exhibit (II) to the partnership agreement. The operator may be replaced at any time upon 60 days advance written notice by the managing general partner acting on behalf of the partnership upon the affirmative vote of investors whose subscriptions equal a majority of the total subscriptions. The drilling and operating agreement provides a number of material provisions, including, without limitation, those set forth below. - The operator's right to resign after five years. - The operator's right beginning three years after a partnership well begins producing to retain $200 per month to cover future plugging and abandonment costs of the well, although the managing general partner historically has never done this after only three years. - 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 the 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 the partnership's ability to transfer its interest in fewer than all wells, unless the transfer is of an equal undivided interest in all wells. - The limitation of the operator's liability except for: - violations of law; - negligence or misconduct by it, its employees, agents or subcontractors; and - breach of the drilling and operating agreement. 126 - The excuse for nonperformance by the operator due to force majeure. - Force majeure generally means acts of God, catastrophes and other causes which preclude the operator's performance and are beyond its control. THE FOREGOING IS A SUMMARY OF THE MATERIAL PROVISIONS OF THE PROPOSED FORM OF DRILLING AND OPERATING AGREEMENT WHICH ARE NOT COVERED ELSEWHERE IN THIS PROSPECTUS. IT IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO THE FORM ATTACHED TO THE PARTNERSHIP AGREEMENT AS EXHIBIT (II). YOU SHOULD NOT SUBSCRIBE TO THE PARTNERSHIP WITHOUT FIRST THOROUGHLY REVIEWING THE DRILLING AND OPERATING AGREEMENT. REPORTS TO INVESTORS Under the partnership agreement you will be provided the reports and information set forth below which the partnership will pay as a direct cost. - Beginning with the 2000 calendar year, the partnership will provide you an annual report within 120 days after the close of the calendar year, and beginning with the 2001 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 in accordance with generally accepted accounting principles. 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, including the percentage that the annual unaccountable, fixed payment reimbursements for administrative costs bears to annual partnership revenues. - A description of each well location 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 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. - By March 15 of each year, the partnership will send you the information needed for you to file your federal and state income tax returns. 127 - Beginning January 1, 2002, and every year thereafter, the managing general partner will provide you a computation of the total oil and gas proved reserves of the partnership and its dollar value. The reserve computations will be based upon engineering reports prepared by the managing general partner and reviewed by an independent expert. PRESENTMENT FEATURE Under the partnership agreement you and the other investors may present your units for repurchase by the managing general partner beginning in 2005. However, you and the other investors are not required to present your units for repurchase and you may receive a greater return if you retain your units. The managing general partner may immediately suspend its repurchase obligation by notice to you if it determines, in its sole discretion, that: - it does not have the necessary cash flow; or - it cannot borrow funds for this purpose on terms it deems reasonable. The managing general partner will not purchase less than one unit unless the lesser amount represents your entire interest. If less than all interests presented at any time are to be purchased, then the interests to be purchased will be selected by lot. In any calendar year the managing general partner will not purchase more than 5% of the units. The managing general partner may waive these limits, other than the limit on its purchasing more than 5% of the units in any calendar year. The managing general partner's obligation to purchase the interests presented may be discharged for its benefit by a third party or an affiliate. If you sell your interest, then it will be transferred to the party who pays for it and you will be required to deliver an executed assignment of your interest along with any other documents that the managing general partner requests. You may present your units in writing to the managing general partner beginning in 2005 subject to the following conditions: - the presentment must be within 120 days of the partnership reserve report discussed below; - in accordance with Treas. Reg. Section 1.7704-1(f), the repurchase may not be made until at least 60 calendar days after you notify the partnership in writing of your presentment; and - the repurchase will not be considered effective until a cash payment has been made to you. The amount attributable to partnership reserves will be determined based upon the last reserve report prepared by the managing general partner and reviewed by an independent expert. Beginning in 2002 the managing general partner will estimate the present worth of future net revenues attributable to the 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 gas prices upon the existing gas contracts at the time of the repurchase. Your presentment price will be based upon your share of the net assets and liabilities of the partnership. It 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; 128 - 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 items: - an amount equal to all debts, obligations and other liabilities, including accrued expenses; and - any distributions made to you between the date of the request and the actual payment. However, if any cash distributed was derived from the sale, after the presentment request, of oil, gas or of a producing property, for purposes of determining the reduction of the presentment price, the 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. The amount may be further adjusted by the managing general partner for estimated changes from the date of the reserve report to the date of payment of the presentment price to you because of 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, gas or other minerals, - revision of regulations relating to the importing of hydrocarbons; and - changes in income, ad valorem and other tax laws such as material variations in the provisions for depletion and similar matters. As of March 31, 2000, fewer than 25 units have been presented to the managing general partner for repurchase in its previous 34 limited partnerships. TRANSFERABILITY OF UNITS RESTRICTIONS ON TRANSFER IMPOSED BY THE SECURITIES AND TAX LAW Your transferability of the units is restricted by the securities laws, the tax laws, and the partnership agreement as described below. First, under the securities laws you will not be able to sell, assign, pledge, hypothecate or transfer your unit unless there is: - an effective registration of the unit under the 1933 Act and qualification under applicable state securities law; or - an opinion of counsel acceptable to the managing general partner that the registration and qualification are not required. The managing general partner and the partnership are not obligated to, and do not intend to, register the units for resale. Second, under the tax laws, 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 the partnership for tax purposes; or 129 - the partnership being treated as a "publicly-traded" partnership for tax purposes. Finally, under the partnership agreement you may not transfer your unit unless the managing general partner consents. The partnership will recognize the assignment of one or more whole units unless you own less than a whole unit, in which case your entire fractional interest must be assigned. Any transfer that is consented to by the managing general partner when the assignee of the unit does not become a substituted partner as described below 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. Under the partnership agreement an assignee of a unit may become a substituted partner only upon meeting certain further conditions. A substitute partner is entitled to all of the rights of full ownership of the assigned units including the right to vote. The conditions to become a substitute partner are as follows: - the assignor of the unit gives the assignee the right; - the managing general partner consents to the substitution; - the assignee of the unit pays to the partnership all costs and expenses incurred in connection with the substitution; and - the assignee of the unit executes and delivers the instruments to effect the substitution and to confirm his agreement to be bound by all terms and provisions of the partnership agreement. 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 will be offered on a "best efforts" basis by Anthem Securities, which is an affiliate of the managing general partner, acting as dealer-manager in all states other than Minnesota and New Hampshire, and by other selected registered broker/dealers, which are members of the 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 an NASD member firm in April, 1997. Anthem Securities has participated as dealer-manager in seven partnerships sponsored by the managing general partner. Bryan Funding, Inc., a member of the NASD, will serve as dealer-manager for the offering in the states of Minnesota and New Hampshire, and will receive the same compensation as Anthem Securities for sales in those states. - Best efforts means that the dealer-manager and selling agents will not guarantee the sale of a certain amount of units. The dealer-manager will manage and oversee the offering of the units as described above and will receive on each unit sold: - a 2.5% dealer-manager fee; - a 7% sales commission; - a .5% reimbursement of marketing expenses; and - a .5% reimbursement of the selling agent's bona fide accountable due diligence expenses. 130 All or a portion of the 7% sales commissions, the .5% reimbursement of marketing expenses, and the .5% reimbursement of the selling agents' bona fide accountable due diligence expenses will be reallowed to the selling agents. The managing general partner is also using the services of four wholesalers, Mr. Eric Koval, Mr. Bruce Bundy, Mr. Robert Gourlay and Ms. Vicki Burbridge who are employed by it or its affiliates and associated with Anthem Securities. The 2.5% dealer-manager fee generally will be reallowed to the affiliated wholesalers for subscriptions obtained through their efforts. The dealer-manager will retain any sales commissions, reimbursement of marketing expenses, and reimbursement of the selling agents' bona fide accountable due diligence expenses not reallowed to the selling agents. The offering will be made in compliance with Rule 2810 of the NASD Conduct Rules and all compensation to broker-dealers and wholesalers, regardless of the source, will be limited to 10% of the gross proceeds of the offering, plus the reimbursement for bona fide accountable due diligence expenses of .5% on each subscription. Also, the offering will be made in compliance with Rule 2810(b)(2)(C) of the NASD 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. You and the other investors will share costs, revenues and distributions in the partnership pro rata in accordance with your respective subscription. Also, the managing general partner, its officers, directors and affiliates and the selling agents may subscribe for units on the same basis as you and other investors but without paying the dealer-manager fee, sales commissions, reimbursement of marketing expenses, and due diligence reimbursements; and registered investment advisors and their clients may subscribe to units without paying sales commissions, reimbursement of marketing expenses, and due diligence reimbursements. These investors will share in the partnership's costs, revenues and distributions on the same basis as the other investors, even though they pay a reduced price for their units. After the minimum subscriptions are received and the checks have cleared the banking system, the dealer-manager fee, the sales commissions, reimbursement of marketing expenses, and due diligence reimbursements will be paid to the dealer-manager and broker/dealers approximately every two weeks until the offering closes. INDEMNIFICATION The dealer-managers may be deemed underwriters as that term is defined in the 1933 Act and the sales commissions and dealer-manager fees may be deemed underwriting compensation. The managing general partner and the dealer-managers have agreed to indemnify each other, and it is anticipated that the dealer-managers 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 will use the following sales material with the offering of the units: - a brochure entitled "Atlas America Public #9 Ltd.", and - Atlas America, Inc.'s corporate profile. 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 must be preceded or accompanied by this prospectus and the sales material is not complete. The sales material 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 units are to be described, offered or sold will clearly indicate the following: 131 - 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 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 representatives of broker/dealers. 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 in this prospectus and its opinion on material tax consequences to individual investors in the partnership. However, the factual statements in this prospectus are those of 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 prospectus for the managing general partner and the partnership have been audited by Grant Thornton, L.L.P., as of the dates indicated in their reports which appear elsewhere in this prospectus. The financial statements have been included in reliance on their reports given on their authority as experts in auditing and accounting. The geologic evaluation of United Energy Development Consultants, Inc., which is not affiliated with the managing general partner and its affiliates, appearing in this prospectus has been included in this prospectus upon the authority of United Energy Development Consultants, Inc. as an expert with respect to the matters covered by the report and in the giving of the report. References in this prospectus to Wright & Company, Inc. and its analysis relating to the September 1999 oil and gas reserves of Resource America, Inc. are made in reliance on Wright & Company, Inc.'s authority as an expert in petroleum consulting. LITIGATION The managing general partner knows of no litigation pending or threatened to which the managing general partner or the partnership is subject or may be a party, which it believes would have a material adverse effect upon the partnership or its business, and no such proceedings are known to be contemplated by governmental authorities or other parties. 132 FINANCIAL INFORMATION CONCERNING THE MANAGING GENERAL PARTNER AND THE PARTNERSHIP Financial information concerning the partnership and the managing general partner is reflected in the following financial statements. 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 THE PARTNERSHIP. 133 FINANCIAL STATEMENT AND REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS ATLAS AMERICA - PUBLIC #9 LTD. A PENNSYLVANIA LIMITED PARTNERSHIP July 31, 2000 134 REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS To the Partners ATLAS AMERICA - PUBLIC #9 LTD. A PENNSYLVANIA LIMITED PARTNERSHIP We have audited the accompanying balance sheet of Atlas America - Public #9 Ltd., a Pennsylvania Limited Partnership, as of July 31, 2000. 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 auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our 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 America - Public #9 Ltd. as of July 31, 2000, in conformity with accounting principles generally accepted in the United States. /s/ GRANT THORNTON LLP Cleveland, Ohio August 15, 2000 135 Atlas America - Public #9 Ltd. (A Pennsylvania Limited Partnership) BALANCE SHEET July 31, 2000
ASSETS Cash $ 100 ==================== PARTNERS' CAPITAL Partners' capital: $ 100 ====================
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THIS FINANCIAL STATEMENT. 136 Atlas America - Public #9 Ltd. (A Pennsylvania Limited Partnership) NOTES TO FINANCIAL STATEMENT July 31, 2000 1. ORGANIZATION AND DESCRIPTION OF BUSINESS Atlas America - Public #9 Ltd. (the "Partnership") is a Pennsylvania Limited Partnership in which Atlas Resources, Inc. ("Atlas") of Pittsburgh, Pennsylvania (a wholly-owned subsidiary of Atlas America, Inc., which is a wholly-owned subsidiary of Resource America, Inc., a publicly traded company) will be Managing General Partner and Operator, and subscribers to Units will be either Limited Partners or Investor General Partners depending upon their election. The Partnership will be funded to drill development wells which are proposed to be located primarily in the Clinton/Medina geological formation in Northwestern Pennsylvania and the Mississippian/Upper Devonian Sandstone reservoir in Fayette County, Pennsylvania, although the Managing General Partner has reserved the right to drill wells in other areas of the United States, primarily in the Appalachian Basin. Subscriptions at a cost of $10,000 per unit will be sold through wholesalers and broker-dealers including Anthem Securities, Inc., an affiliated company, which will be compensated in an amount equal to 10% of the subscription plus a .5% accountable due diligence fee. Commencement of Partnership operations is subject to the receipt of minimum Partnership subscriptions of $1,000,000 (to a maximum of $15,000,000) by December 31, 2000. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The financial statements are prepared in accordance with generally accepted accounting principles. 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. The preparation of financial statements in conformity with generally accepted accounting principles 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. 137 Atlas America - Public #9 Ltd. (A Pennsylvania Limited Partnership) NOTES TO FINANCIAL STATEMENT - CONTINUED July 31, 2000 3. FEDERAL INCOME TAXES The Partnership is not treated as a taxable entity for federal income tax purposes. Any item of income, gain, loss, deduction or credit flows through to the partners as though each partner had incurred such item directly. As a result, each partner must take into account his pro rata share of all items of partnership income and deductions in computing his federal income tax liability. 4. PARTICIPATION IN REVENUES AND COSTS Atlas and the other partners will participate in revenues and costs in the following manner:
OTHER ATLAS PARTNERS ------------------- ----------------- Organization costs 100% 0% Dealer-manager fee, sales commissions, and reimbursement for bona fide accountable due diligence expenses 0% 100% Reimbursement of marketing expenses 100% 0% Lease costs 100% 0% Revenues (1) (1) Operating costs, administrative costs, direct costs and all other costs (2) (2) Intangible drilling costs 0% 100% Tangible costs 100% 0% Tax deductions: Intangible drilling and development costs 0% 100% Depreciation 100% 0% Depletion allowances (3) (3)
(1) Subject to the Managing General Partner's subordination obligation, substantially all revenues will be credited as follows: before net of tax savings payout and partnership payout, partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions. After net of tax savings payout, the Managing General Partner will receive an additional 6.5% of the partnership revenues, and after partnership payout, the Managing General Partner will receive an additional 8.5% of partnership revenues. (2) These costs will be charged to the partners in the same ratio as the related production revenues are credited. (3) The percentage depletion allowance will be in the same percentages as the production revenues. 138 Atlas America - Public #9 Ltd. (A Pennsylvania Limited Partnership) NOTES TO FINANCIAL STATEMENT - CONTINUED July 31, 2000 5. TRANSACTIONS WITH ATLAS AND ITS AFFILIATES The Partnership intends to enter into the following significant transactions with Atlas and its affiliates as provided under the Partnership agreement: Drilling contracts to drill and complete Partnership wells at cost plus 15%. Administrative costs at $75 per well per month. Well supervision fees for operating and maintaining the wells during producing operations at a competitive rate (currently in the range of $275 to $400 per well per month. Reimbursement of gas transportation at competitive rates (currently in the range of $.29 to $.35 per MCF). 6. PURCHASE COMMITMENT Subject to certain conditions, investor partners may present their interests beginning in 2005 for purchase by Atlas. Atlas is not obligated to purchase more than 5% of the units in any calendar year. In the event that Atlas is unable to obtain the necessary funds, Atlas may suspend its repurchase obligation. 7. SUBORDINATION OF MANAGING GENERAL PARTNER'S REVENUE SHARE Atlas will subordinate up to 50% of its share of production revenues of the Partnership, net of related operating costs, administrative costs and well supervision fees to the receipt by participants of cash distributions from the Partnership equal to at least 10% of their agreed subscriptions, determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution of revenues to the participants. 8. INDEMNIFICATION In order to limit the potential liability of the investor general partners, Atlas has agreed to indemnify each investor general partner from any liability incurred which exceeds such partner's share of Partnership assets. 139 CONSOLIDATED FINANCIAL STATEMENTS AND REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS ATLAS RESOURCES, INC. September 30, 1999 and 1998 140 REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS Board of Directors ATLAS AMERICA, INC. We have audited the accompanying consolidated balance sheets of Atlas Resources, Inc. (a Pennsylvania corporation) and Subsidiary as of September 30, 1999 and 1998, and the related consolidated statements of earnings and retained earnings, and cash flows for the year ended September 30, 1999. 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 generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Atlas Resources, Inc. and Subsidiary as of September 30, 1999 and 1998, and the consolidated results of their operations and their consolidated cash flows for the year ended September 30, 1999, in conformity with generally accepted accounting principles. /s/ GRANT THORNTON LLP Cleveland, Ohio November 17, 1999 141 Atlas Resources, Inc. and Subsidiary CONSOLIDATED BALANCE SHEETS September 30 ASSETS
1999 1998 ------------------- ------------------- Current Assets Cash and cash equivalents $ 9,417,386 $ 83,890 Accounts and other receivables 3,686,386 2,918,819 Inventories 331,019 160,890 Prepaid expenses and other current assets 63,599 25,987 ------------------- ------------------- Total current assets 13,498,390 3,189,586 Property, Plant and Equipment - at cost Oil and gas properties and equipment (successful efforts) 21,968,332 13,290,245 Land 361,000 361,000 Buildings 2,469,000 2,469,000 Equipment 378,029 209,964 ------------------- ------------------- 25,176,361 16,330,209 Less accumulated depreciation and amortization (1,705,672) - ------------------- ------------------- Net property, plant and equipment 23,470,689 16,330,209 Contract rights and other intangibles (less accumulated 11,481,913 12,095,708 amortization of $613,795 in 1999) Goodwill (less accumulated amortization of $536,263 in 1999) 15,551,595 16,087,858 ------------------- ------------------- $ 64,002,587 $47,703,361 =================== =================== LIABILITIES AND STOCKHOLDER'S EQUITY Current Liabilities Accounts payable and accrued liabilities $ 3,830,648 $ 801,488 Working interests and royalties payable 4,397,894 4,723,751 Billings in excess of costs on uncompleted contracts 4,815,172 5,290,633 Current maturities of long-term debt 185,714 185,714 ------------------- ------------------- Total current liabilities 13,229,428 11,001,586 Deferred Taxes 1,688,480 919,000 Advances from Parent and affiliates 5,965,392 1,166,755 Long-Term Debt, net of current maturities 5,315,477 526,191 Stockholder's Equity Capital stock - stated value $10 per share; authorized - 500 shares, issued and outstanding - 200 shares 2,000 2,000 Additional paid-in capital 34,087,829 34,087,829 Retained earnings 3,713,981 - ------------------- ------------------- 37,803,810 34,089,829 ------------------- ------------------- $ 64,002,587 $47,703,361 =================== ===================
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS. 142 Atlas Resources, Inc. and Subsidiary CONSOLIDATED STATEMENT OF EARNINGS AND RETAINED EARNINGS For the year ended September 30, 1999 REVENUES Well drilling $29,183,206 Oil and gas production 3,966,063 Well services 3,537,652 Other income 178,776 -------------------- 36,865,697 COSTS AND EXPENSES Well drilling 24,082,593 Oil and gas production 1,820,000 Well services 224,491 Exploration 175,806 General and administrative 854,411 Depreciation, depletion and amortization 2,855,730 Interest 490,930 Other 154,800 -------------------- 30,658,761 -------------------- Earnings from operations 6,206,936 Provision for income taxes 2,492,955 -------------------- NET EARNINGS 3,713,981 Retained earnings - beginning of year - -------------------- Retained earnings - end of year $ 3,713,981 ====================
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THIS STATEMENT. 143 Atlas Resources, Inc. and Subsidiary CONSOLIDATED STATEMENT OF CASH FLOWS For the year ended September 30, 1999 CASH FLOWS FROM OPERATING ACTIVITIES Net earnings $ 3,713,981 Adjustments to reconcile net earnings to net cash provided by operating activities: Depreciation, depletion and amortization 2,855,730 Deferred income taxes 769,480 Changes in operating assets and liabilities: Increase in accounts receivable (767,567) Increase in inventory (170,129) Increase in prepaid expenses and other current assets (37,612) Increase in accounts payable and accrued liabilities 3,029,160 Decrease in working interests and royalties payable (325,857) Decrease in billings in excess of costs on uncompleted contracts (475,461) -------------------- Cash provided by operating activities 8,591,725 CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (8,846,152) -------------------- Cash used in investing activities (8,846,152) CASH FLOWS FROM FINANCING ACTIVITIES Advances from Parent 4,798,637 Payment on mortgage payable (185,714) Borrowings on revolving credit loan 4,975,000 -------------------- Cash provided by financing activities 9,587,923 -------------------- INCREASE IN CASH AND CASH EQUIVALENTS 9,333,496 Cash and cash equivalents at beginning of period 83,890 -------------------- Cash and cash equivalents at end of period $ 9,417,386 ====================
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THIS STATEMENT. 144 Atlas Resources, Inc. and Subsidiary NOTES TO CONSOLIDATED FINANCIAL STATEMENTS September 30, 1999 and 1998 NOTE A - NATURE OF OPERATIONS Atlas Resources, Inc. (the "Company") and its subsidiary, ARD Investments, are engaged in the exploration for development and production of natural gas and oil primarily in the Appalachian Basin Area. In addition, the Company performs contract drilling and well operation services. Atlas Resources, Inc. is a wholly-owned subsidiary of AIC, Inc. which is a wholly-owned subsidiary of Atlas America, Inc. (formerly The Atlas Group, Inc.). Atlas America, Inc. is a wholly-owned subsidiary of Resource America, Inc. which is a publicly traded company (trading under the symbol REXI on the NASDAQ System) operating in the real estate finance, leasing and energy business sectors. The Company is affiliated to other companies which are subsidiaries of AIC, Inc. The Company's operations are dependent upon the resources and services provided by AIC, Inc. The company is also the managing general partner of several oil and gas partnerships. On September 29, 1998, Atlas America, Inc. acquired all the common stock of The Atlas Group, Inc. in exchange for 2,063,496 shares of Resource America, Inc. common stock worth approximately $29,534,000 and the assumption of debt. The acquisition was recorded under the purchase method of accounting and accordingly the purchase price was allocated to assets acquired and liabilities assumed based on their fair market values, at the date of acquisition, as summarized below: Fair value of assets acquired $ 71,951,000 Liabilities assumed (43,284,000) Amounts due seller (9,191,000) Common stock issued (29,534,000) ------------------ NET CASH ACQUIRED $ (10,058,000) ==================
NOTE B - SUMMARY OF ACCOUNTING POLICIES A summary of significant accounting policies consistently applied in the preparation of the accompanying consolidated financial statements follows. PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiary. The Company owns an undivided interest in the assets and is separately liable for its share of liabilities of partnerships in which it has an ownership interest. In accordance with established practice in the oil and gas industry, the Company includes its pro rata share of the assets, liabilities, income and expenses of such partnerships in the consolidated financial statements. All significant intercompany transactions and balances have been eliminated. Certain reclassifications have been made to the 1998 financial statements to conform to the 1999 presentation. 145 Atlas Resources, Inc. and Subsidiary NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED September 30, 1999 and 1998 NOTE B - SUMMARY OF ACCOUNTING POLICIES (CONTINUED) USE OF ESTIMATES Preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. INVENTORIES Inventories, consisting of oil and gas field materials and supplies, are stated at the lower of cost or market. Cost is determined by the first-in, first-out method. OIL AND GAS PROPERTIES The Company follows the successful efforts method of accounting. Accordingly, property acquisition costs, costs of successful exploratory wells, all development costs, and the cost of support equipment and facilities are capitalized. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be nonproductive. The costs associated with drilling and equipping wells not yet completed are capitalized as uncompleted wells, equipment and facilities. Geological and geophysical costs and the costs of carrying and retaining undeveloped properties, including delay rentals, are expensed. Production costs, overhead, and all exploration costs other than costs of exploratory drilling are charged to expense as incurred. Proved developed oil and gas properties, which include intangible drilling and development costs, tangible well equipment and leasehold costs, are amortized on the unit-of-production method using the ratio of current production to the estimated aggregate proved developed oil and gas reserves. Unproved properties are assessed periodically to determine whether there has been a decline in value and, if such decline is indicated, a loss will be recognized. The Company compares the carrying value of its oil and gas producing properties to the estimated future cash flow, net of applicable income taxes, from such properties in order to determine whether their carrying values should be reduced. No adjustment was necessary at September 30, 1999. On an annual basis, the Company estimates the costs of future dismantlement, restoration, reclamation, and abandonment of its gas and oil producing properties. Additionally, the Company evaluates the estimated salvage value of equipment recoverable upon abandonment. At September 30, 1999 and 1998, the Company's evaluation of equipment salvage values was greater than or equal to the estimated costs of future dismantlement, restoration, reclamation and abandonment. 146 Atlas Resources, Inc. and Subsidiary NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED September 30, 1999 and 1998 NOTE B - SUMMARY OF ACCOUNTING POLICIES (CONTINUED) PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment, other than oil and gas properties, is stated at their estimated fair value at the date of acquisition while subsequent additions are recorded at cost. Depreciation is provided using the straight-line method over the following estimated useful lives once the asset is put into productive use. Equipment 5 - 7 years Building 39 years LONG-LIVED ASSETS Contract rights and other intangibles consist of contracts purchased to operate wells and manage limited partnerships and the ongoing partnership syndication business. Operating and management contracts are being amortized on a straight-line basis over the lives of the respective partnerships (up to 13 years) while the syndication rights are being amortized on a straight-line basis over 30 years. Goodwill is the excess of cost over the fair value of net assets acquired and is being amortized by the straight-line method over 30 years. The Company evaluates both contract rights and goodwill periodically to determine potential impairment by comparing the carrying value to the undiscounted estimated future cash flows of the related assets. BILLINGS IN EXCESS OF COSTS ON UNCOMPLETED CONTRACTS Amounts billed that are in excess of costs incurred are classified as a current liability under billings in excess of costs on uncompleted contracts. Contract costs include all direct material and labor costs and those indirect costs related to contract performance, such as indirect labor, supplies, repairs and depreciation costs. Contract retentions are included in accounts receivable. REVENUE RECOGNITION The Company sells interests in oil and gas wells and retains there from a working interest and/or overriding royalty in the producing wells. The income from the working interests is recorded when the natural gas and oil are produced. The Company also contracts to drill oil and gas wells. The income from these contracts is recorded upon substantial completion of the well. 147 Atlas Resources, Inc. and Subsidiary NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED September 30, 1999 and 1998 NOTE B - SUMMARY OF ACCOUNTING POLICIES (CONTINUED) IMPAIRMENT OF LONG-LIVED ASSETS The Company reviews its long-lived assets for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. If it is determined that an asset's estimated future cash flows will not be sufficient to recover its carrying amount, an impairment charge will be recorded to reduce the carrying amount for that asset to its estimated fair value. FEDERAL INCOME TAXES The Company is included in the consolidated federal income tax return of Resource America, Inc. Income taxes are calculated as if the Company had filed a return on a separate company basis utilizing a statutory rate of 35%. Deferred taxes represent deferred tax assets or liabilities which are recognized based on the temporary differences between the tax basis of the Company's assets and liabilities and the amounts reported in the financial statements. Separate company state tax returns are filed in those states in which the Company is registered to do business. FAIR VALUE OF FINANCIAL INSTRUMENTS For cash and cash equivalents, receivable and payables, the carrying amounts approximate fair value because of the short maturity of these instruments. For long-term debt, the fair value approximates historically recorded cost, since interest rates approximate market. Management believes the fair value of any financial commitments are not material. SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Cash paid during the year for:
YEAR ENDED SEPTEMBER 30, 1999 ------------------------------- Interest $ 50,707 ------------------------------- Income taxes $145,106 ===============================
148 Atlas Resources, Inc. and Subsidiary NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED September 30, 1999 and 1998 NOTE B - SUMMARY OF ACCOUNTING POLICIES (CONTINUED) NEW ACCOUNTING STANDARDS Effective October 1, 1998, the Company became subject to the provisions of Statements of Financial Accounting Standards No. 130 (SFAS 130), REPORTING COMPREHENSIVE INCOME requires disclosure of comprehensive income and its components. Comprehensive income includes net income and all other changes in 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". The Company has no material elements of comprehensive income, other than net income to report. In June 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 133 (SFAS 133), ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND HEDGING. SFAS 133 will require the Company to recognize all derivatives as either assets or liabilities in its consolidated balance sheet and to measure those instruments at fair value. The Company is required to adopt SFAS 133 effective October 1, 2000. The effect of adopting SFAS 133 on the Company's consolidated financial position, results of operations and cash flows will be dependent on the extent of future hedging activities and fluctuations in interest rates. NOTE C - RELATED PARTY TRANSACTIONS The Company conducts certain energy activities through, and a substantial portion of its revenues are attributable to limited partnerships ("Partnerships"). The Company serves as general partner of the Partnerships and assumes customary rights and obligations for the Partnerships. As the general partner, the Company is liable for Partnership liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Partnerships. The Company is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Partnerships' revenue and costs and expenses according to the respective Partnership agreements. NOTE D - INCOME TAXES The Company is included in the consolidated federal income tax return filed by Resource America, Inc., the parent company. Allocation of income tax provision or benefit is based on actual tax calculations of the individual companies and settled through increases or decreases to the Advances from Parent and affiliates balance. The Company records deferred tax assets and liabilities based on the temporary differences between the financial statement and tax bases of assets and liabilities. The net deferred tax liability at September 30, 1999 was primarily related to differences between book and tax bases of oil and gas properties. 149 Atlas Resources, Inc. and Subsidiary NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED September 30, 1999 and 1998 NOTE E - LONG-TERM DEBT Long-term debt consists of the following:
SEPTEMBER 30, ----------------------------------- 1999 1998 --------------- ------------------- Note payable to bank, secured by a building and certain equipment, monthly installments of $15,476 plus interest at or below the LIBOR rate plus 2-1/4% (7.5625% at September 30, 1999); due August 2002 $526,191 $711,905 Revolving credit facility, secured by oil and gas properties and pipelines; interest ranging from 7.0625% to 9% due November 2002 4,975,000 - --------------- ------------------- 5,501,191 711,905 Less current portion 185,714 185,714 --------------- ------------------- $5,315,477 $526,191 =============== ===================
Atlas America, Inc. (Atlas), along with other energy affiliates owned by Resource America, Inc., maintain a $45.0 million credit facility (with $22.0 million of permitted draws available to Atlas) at PNC Bank ("PNC"). The facility is cross collateralized by the assets of all of the energy affiliates, and a breach of the loan agreement by any of the energy affiliates would constitute a default by Atlas. The revolving credit facility has a term ending in November 2002 and bears interest at one of two rates (elected at the borrower's option) which increase as the amount outstanding under the facility increases: (i) PNC prime rate plus between 0 to 75 basis points, or (ii) the Eurodollar rate plus between 150 to 225 basis points. The credit facility contains certain financial covenants and imposes the following limits: (a) Atlas' exploration expense can be no more than 20% of capital expenditures plus exploration expense, without PNC's consent; (b) limitations on indebtedness, sales, leases or transfers of property by Atlas without PNC's consent; and (c) the maintenance of certain financial ratios. Borrowings under the credit facility are collateralized by substantially all the oil and gas properties and pipelines of Atlas. Maturities of all long-term debt for the years following September 30, 1999 are as follows: 2000 - $185,714; 2001 - $185,714; 2002 - $154,763; and 2003 - $4,975,000. 150 Atlas Resources, Inc. and Subsidiary NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED September 30, 1999 and 1998 NOTE F - COMMITMENTS The Company is the managing general partner in several oil and gas limited partnerships, and Atlas America, Inc. has agreed to indemnify each investor general partner from any liability which exceeds such partner's share of partnership assets. Management believes that any such liabilities that may occur will be covered by insurance and, if not covered by insurance, will not result in a significant loss to Atlas America, Inc. and its subsidiaries. Subject to certain conditions, investor partners in certain oil and gas limited 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% or 10% of the units in any calendar year. The Company may be required to subordinate a part of its net partnership revenues to the receipt by investor partners of cash distributions from the Partnership equal to at least 10% of their agreed subscriptions determined on a cumulative basis, in accordance with the terms of the partnership agreement. NOTE G - FUTURES CONTRACTS The Company enters into natural gas futures contracts to hedge its exposure to changes in natural gas prices. At any point in time, such contracts may include regulated NYMEX futures contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The futures contracts employed by the Company are commitments to purchase or sell natural gas at future date and generally cover one-month periods for up to 18 months in the future. Gains and losses on such contracts are deferred and recognized in the month the gas is sold. The Company had no significant futures contracts at September 30, 1999. NOTE H - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) Results of operations for oil and gas producing activities:
YEAR ENDED SEPTEMBER 30, 1999 ------------------------- Revenues $ 3,966,063 Production Costs (1,820,000) Exploration Expenses (175,806) Depreciation, Depletion and Amortization (1,594,894) Income Taxes - ------------------------- RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES $ 375,363 =========================
151 Atlas Resources, Inc. and Subsidiary NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED September 30, 1999 and 1998 NOTE H - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (CONTINUED) The estimates of the Company's proved and unproved gas reserves are based upon evaluations verified by Wright & Company Inc., an independent petroleum engineering firm, as of September 30, 1999 and 1998. All reserves are located in the Appalachian Basin Area. 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 provision for price and cost escalation except by contractual arrangements. Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs. Proved developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. The components of capitalized costs related to the Company's oil and gas producing activities are as follows:
SEPTEMBER 30 --------------------------------------- 1999 1998 -------------------- ------------------ Proved properties $21,946,148 $13,279,245 Unproved properties 22,184 11,000 -------------------- ------------------ Total 21,968,332 13,290,245 Accumulated depreciation, depletion and amortization (1,594,894) - -------------------- ------------------ NET CAPITALIZED COSTS $20,373,438 $13,290,245 ==================== ==================
The costs incurred by the Company in its oil and gas activities during the fiscal year are as follows:
YEAR ENDED SEPTEMBER 30, 1999 -------------------------- Property acquisition costs: Unproved properties $ 11,184 Proved properties 15,519 Exploration costs 175,806 Development costs $ 8,651,384
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 standarized measures of discounted future net cash flows may not represent the fair market value of the Company's oil and gas reserves or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors for which effects have not been provided. 152 Atlas Resources, Inc. and Subsidiary NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED September 30, 1999 and 1998 NOTE H - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (CONTINUED) The standardized measure of discounted future net cash flows is information provided for the financial statement user as a common base for comparing oil and gas reserves of enterprises in the industry. The following schedule presents the standardized measure of estimated discounted future net cash flows from the Company's proved reserves. Estimated future cash flows are determined by using the weighted average price received for the month of each fiscal year, adjusted only for fixed and determinable increases in natural gas prices provided by contractual agreements. The standardized measure of future net cash flows was prepared using the prevailing economic conditions existing at September 30, 1999 and 1998 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.
GAS OIL (MCF) (BBLS) ------------------- ------------------ Proved developed and undeveloped reserves at September 30, 1998: 65,376,210 4,574 Current additions 29,705,025 - Revision of previous estimates (4,939,305) (2,437) Transfer to limited partnerships (18,221,632) - Production (2,432,098) (354) ------------------- ------------------ Proved developed and undeveloped reserves at September 30, 1999 69,488,200 1,783 =================== ================== Proved developed reserves at: September 30, 1999 27,531,938 1,783 =================== ================== September 30, 1998 25,360,750 4,574 =================== ==================
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED RESERVES
SEPTEMBER 30 ------------------------------------------ 1999 1998 ---------------------- ------------------- Future cash inflows $202,362,311 $152,909,040 Future production and development costs 99,691,650 73,423,000 ---------------------- ------------------- Future net cash flows before income taxes 102,670,661 79,486,040 Future income taxes 13,861,715 3,853,561 ---------------------- ------------------- Future net cash flows 88,808,946 75,632,479 Annual discount for estimated timing of cash flows 62,275,451 56,231,521 ---------------------- ------------------- Standardized measure of discounted future net cash flows $26,533,495 $ 19,400,968 ====================== ===================
153 Atlas Resources, Inc. and Subsidiary NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED September 30, 1999 and 1998 NOTE H - SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED) (CONTINUED) The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved developed and undeveloped oil and gas reserves after income taxes.
YEAR ENDED SEPTEMBER 30, 1999 -------------------------- Balance, beginning of year $19,400,968 Increase (decrease) in discounted future net cash flows: Sales and transfers of oil and gas net of related costs (2,146,063) Net changes in prices and production costs 1,033,939 Revisions of previous quantity estimates (3,744,734) Extensions, discoveries, and improved recovery, less related costs - Purchases of reserves-in-place 10,412,270 Accretion of discount 2,043,105 Net change in future income taxes (1,306,947) Other 840,957 ------------------------- BALANCE, END OF YEAR $26,533,495 =========================
154 CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) ATLAS RESOURCES, INC. JUNE 30, 2000 155 ATLAS RESOURCES, INC. CONSOLIDATED BALANCE SHEETS (UNAUDITED)
6/30/2000 9/30/99 (Unaudited) ASSETS CURRENT ASSETS Cash and cash equivalents $ 5,490,541 $ 9,417,386 Trade accounts receivable 6,203,668 3,686,386 Inventories 470,857 331,019 Other current assets 72,016 63,599 ------------ ------------ TOTAL CURRENT ASSETS 12,237,082 13,498,390 ------------ ------------ OIL AND GAS PROPERTIES Oil and gas wells and leases 27,493,472 21,968,332 Less accumulated depreciation, depletion and amortization 2,953,902 1,594,894 ------------ ------------ NET OIL & GAS PROPERTIES 24,539,570 20,373,438 ------------ ------------ OTHER PROPERTY, PLANT AND EQUIPMENT Land 361,000 361,000 Buildings 2,469,000 2,469,000 Equipment 349,168 378,029 ------------ ------------ Sub-total 3,179,168 3,208,029 Less accumulated depreciation 187,421 110,778 ------------ ------------ NET OTHER PROPERTY, PLANT & EQUIPMENT 2,991,747 3,097,251 ------------ ------------ Contract rights and other intangibles(Net of accumulated amortization of $1,074,145 and $613,795) 11,021,563 11,481,913 Goodwill(Net of accumulated amortization of $938,458 and $536,263) 15,149,400 15,551,595 ------------ ------------ TOTAL ASSETS $ 65,939,362 $ 64,002,587 ============ ============ LIABILITIES AND STOCKHOLDER'S EQUITY CURRENT LIABILITIES Accounts payable and accrued liabilities $ 425,734 $ 3,830,648 Working interests and royalties payable 5,212,668 4,397,894 Billings in excess of costs on uncompleted contracts 3,330,990 4,815,172 Current maturities on long-term debt 185,714 185,714 ------------ ------------ TOTAL CURRENT LIABILITIES 9,155,106 13,229,428 ------------ ------------ LONG-TERM DEBT, net of current maturities 216,667 5,315,477 ------------ ------------ ADVANCES FROM PARENT & AFFILIATES 14,092,269 5,965,392 ------------ ------------ DEFERRED INCOME TAXES 2,143,337 1,688,480 ------------ ------------ STOCKHOLDER'S EQUITY Capital stock, stated value $10.00 per share: Authorized - 500 shs; Issued - 200 shs. 2,000 2,000 Additional Paid in Capital 34,087,829 34,087,829 Retained earnings 6,242,154 3,713,981 ------------ ------------ TOTAL STOCKHOLDER'S EQUITY 40,331,983 37,803,810 ------------ ------------ TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY $ 65,939,362 $ 64,002,587 ============ ============
156 ATLAS RESOURCES, INC. CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
NINE MONTHS ENDED JUNE 30 ------------------------- 2000 1999 ---- ---- REVENUES Well drilling $ 21,789,141 $ 24,669,120 Oil and gas production 4,322,881 3,413,813 Well services 2,326,924 1,980,255 Interest 54,577 27,580 Other 199,528 314,422 ------------ ------------ TOTAL REVENUES 28,693,051 30,405,190 ------------ ------------ COSTS AND EXPENSES Well drilling 18,054,058 20,133,912 Oil and gas production 1,098,420 737,791 Depreciation, depletion and amortization 2,300,546 2,030,003 Exploration 202,852 129,304 General and administrative 2,205,728 1,240,567 Interest 327,228 261,176 Other 248,036 126,944 ------------ ------------ TOTAL COSTS AND EXPENSES 24,436,868 24,659,697 ------------ ------------ INCOME BEFORE INCOME TAXES 4,256,183 5,745,493 INCOME TAXES 1,728,010 2,334,221 ------------ ------------ NET INCOME $ 2,528,173 $ 3,411,272 ============ ============
ATLAS RESOURCES, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
NINE MONTHS ENDED JUNE 30 ------------------------- 2000 1999 ------------ ------------ CASH FLOWS FROM OPERATING ACTIVITIES: Net Income $ 2,528,173 $ 3,411,272 Adjustments to reconcile net income to net cash provided by (used in) operating activities: Depreciation, depletion and amortization 2,300,546 2,030,003 Deferred Income Taxes 454,857 -- (Increase) in Current Assets (2,665,537) (2,400,443) Increase (Decrease) in Current Liabilities (4,074,322) 8,093,913 ------------ ------------ Net cash provided by (used in) operating activities (1,456,283) 11,134,745 ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES: Investment in oil and gas wells and leases (5,525,140) (6,323,735) Investment in other property, plant & equipment (23,177) (7,738) Sale of other property, plant & equipment 49,457 -- ------------ ------------ Net cash used in investing activities (5,498,859) (6,331,473) ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings/(Repayments) under revolving credit (4,975,000) 5,425,000 Advances from parent & affiliates 8,127,108 -- Repayment of bank notes (123,810) (139,286) ------------ ------------ Net cash provided by (used in) financing activities 3,028,298 5,285,714 ------------ ------------ Net increase (decrease) in cash and cash equivalents (3,926,845) 10,088,986 Cash and cash equivalents at beginning of year 9,417,386 62,724 ------------ ------------ Cash and cash equivalents at end of period $ 5,490,541 $ 10,151,710 ============ ============
157 ATLAS RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) June 30, 2000 1. INTERIM FINANCIAL STATEMENTS The consolidated financial statements as of June 30, 2000 and for the nine months then ended have been prepared by the management of the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in the financial statements prepared in accordance with generally accepted accounting principles have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with the audited September 30, 1999 consolidated financial statements. In the opinion of management, all adjustments (consisting of only normal recurring accruals) considered necessary for presentation have been included. 2. CONSOLIDATED STATEMENTS OF CASH FLOWS Supplemental disclosure of cash flow information:
Nine Months Ended June 30, 2000 1999 Cash paid during the period for: Interest $341,140 $218,950 Income taxes 268,000 266,000
3. LONG-TERM DEBT Long-term debt consists of a note payable to a bank in the amount of $402,381 which is payable in monthly installments of $15,476 plus interest at Libor plus 2 1/4% (8.94% at June 30, 2000) or the prime rate plus 1/2% at the borrower's option and is due August of 2002. The note is secured by a building and certain equipment. Maturities of the note payable for the years following June 30, 2000 are as follows: 158 Period Ending June 30, 2001 185,714 2002 185,714 Final Maturity August, 2002 30,953 -------- 402,381 Less current maturities 185,714 -------- $216,667 ======== Atlas America, Inc., the parent company of Atlas Resources, Inc. together with other energy affiliates of Atlas America, maintain a $40.0 million credit facility (with $33.7 million of permitted draws) with a bank group with PNC Bank as the agent bank. As of June 30, 2000, Atlas Resources, Inc. had no balance outstanding under the revolving credit facility. 159 EXHIBIT (A) AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP ATLAS AMERICA PUBLIC #9 LTD. 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................................2 III. SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS 3.01 Designation of Managing General Partner and Participants......................10 3.02 Participants..............................10 3.03 Subscriptions to the Partnership..........11 3.04 Capital Contributions.....................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.....................16 4.03 General Rights and Obligations of the Participants and Restricted and Prohibited Transactions...............20 4.04 Designation, Compensation and Removal of Managing General Partner and Removal of Operator.......29 4.05 Indemnification and Exoneration...........31 4.06 Other Activities..........................33 V. PARTICIPATION IN COSTS AND REVENUES, CAPITAL ACCOUNTS, ELECTIONS AND DISTRIBUTIONS 5.01 Participation in Costs and Revenues.......34 5.02 Capital Accounts and Allocations Thereto...............................37 5.03 Allocation of Income, Deductions and Credits...............................38 5.04 Elections.................................40 5.05 Distributions.............................40 VI. TRANSFER OF INTERESTS 6.01 Transferability...........................41 6.02 Special Restrictions on Transfers.........42 6.03 Right of Managing General Partner to Hypothecate and/or Withdraw Its Interests....................43 6.04 Presentment...............................44 VII. DURATION, DISSOLUTION, AND WINDING UP 7.01 Duration....................................46 7.02 Dissolution and Winding Up..................46 VIII. MISCELLANEOUS PROVISIONS 8.01 Notices.....................................47 8.02 Time........................................47 8.03 Applicable Law..............................47 8.04 Agreement in Counterparts...................47 8.05 Amendment...................................48 8.06 Additional Partners.........................48 8.07 Legal Effect................................48 EXHIBITS EXHIBIT (I-A) - Managing General Partner Signature Page EXHIBIT (I-B) - Subscription Agreement EXHIBIT (II) - Drilling and Operating Agreement i AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP ATLAS AMERICA PUBLIC #9 LTD. 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 _____________________, 2000, by and among Atlas Resources, Inc., hereinafter 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 hereinafter sometimes referred to as "Limited Partners," or for Investor General Partner Units, these parties hereinafter sometimes referred to as "Investor General Partners." ARTICLE I FORMATION 1.01. FORMATION. The parties hereto form a limited partnership pursuant to the Pennsylvania Revised Uniform Limited Partnership Act, upon the terms and conditions set forth herein. 1.02. CERTIFICATE OF LIMITED PARTNERSHIP. This document shall constitute not only the agreement among the parties hereto, but also shall constitute 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 America Public #9 Ltd. 1.03(b). RESIDENCE. The residence of the Managing General Partner shall be its principal place of business at 311 Rouser Road, 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 each party. All addresses shall be subject to change upon 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 Mr. Tony C. Banks at Atlas Resources, Inc., 311 Rouser Road, Moon Township, Pennsylvania 15108. 1.04. PURPOSE. The Partnership shall engage in all phases of the oil and gas business. This includes, without limitation, exploration for, development and production of oil and gas upon the terms and conditions hereinafter set forth and any other proper purpose under the Pennsylvania Revised Uniform Limited Partnership Act. The Managing General Partner may not, without the affirmative vote of Participants whose Agreed Subscriptions equal a majority of the Partnership Subscription, 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. 1 ARTICLE II DEFINITION OF TERMS 2.01. DEFINITIONS. As used in this Agreement, the following terms shall have the meanings hereinafter set forth: 1. "Administrative Costs" shall mean all customary and routine expenses incurred by the Sponsor for the conduct of Partnership administration, including: legal, finance, 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 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. 2. "Administrator" shall mean the official or agency administering the securities laws of a state. 3. "Affiliate" shall mean 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. 4. "Agreed Subscription" shall mean: (i) that amount so designated on the Subscription Agreement executed by the Participant; or (ii) in the case of the Managing General Partner, its subscription under Section 3.03(b) and its subsections. 5. "Agreement" shall mean this Amended and Restated Certificate and Agreement of Limited Partnership, including all exhibits hereto. 6. "Anthem Securities" shall mean Anthem Securities, Inc., whose principal executive offices are located at 311 Rouser Road, P.O. Box 926, Coraopolis, Pennsylvania 15108-0926. 7. "Assessments" shall mean additional amounts of capital which may be mandatorily required of or paid voluntarily by a Participant beyond his subscription commitment. 8. "Atlas" shall mean Atlas Resources, Inc., a Pennsylvania corporation, whose principal executive offices are located at 311 Rouser Road, Moon Township, Pennsylvania 15108. 2 9. "Capital Account" or "account" shall mean the account established for each party hereto, maintained as provided in Section 5.02 and its subsections. 10. "Capital Contribution" shall mean the amount agreed to be contributed to the Partnership by a party pursuant to Sections 3.04 and 3.05 and their subsections. 11. "Carried Interest" shall mean 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" shall mean the Internal Revenue Code of 1986, as amended. 13. "Cost," when used with respect to the sale of property to the Partnership, shall mean: (i) the sum of the prices paid by the seller 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 actual necessary and reasonable expenses for seismic and geophysical services; and (iv) rentals and ad valorem taxes paid by the seller with respect to 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 reasonable, necessary and actual expenses for geological, 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 purchase by the Partnership. "Cost," when used with respect to services, shall mean 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" shall mean the price paid by the seller in an arm's-length transaction. 14. "Dealer-Manager" shall mean: (i) Anthem Securities, Inc., an Affiliate of the Managing General Partner, the broker/dealer which will manage the offering and sale of the Units in all states other than Minnesota and New Hampshire; and (ii) Bryan Funding, Inc., the broker/dealer which will manage the offering and sale of Units in Minnesota and New Hampshire. 15. "Development Well" shall mean a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic Horizon known to be productive. 16. "Direct Costs" shall mean 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 shall be limited as follows: (i) Direct Costs shall not include any cost otherwise classified as Organization Costs, Administrative Costs, Intangible Drilling Costs, Tangible Costs, Operating Costs or costs related to the Leases; and 3 (ii) Direct Costs 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 Section 4.03(d)(7). 17. "Distribution Interest" shall mean an undivided interest in the assets of the Partnership after payments to creditors of the Partnership 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 assets of the Partnership shall equal a party's interest in the related revenues of the Partnership as set forth in Section 5.01 and its subsections of this Agreement; including the Managing General Partner's increased interests after Net of Tax Savings Payout and Partnership Payout. 18. "Drilling and Operating Agreement" shall mean 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 hereto as Exhibit (II). 19. "Exploratory Well" shall mean a well drilled: (i) to find commercially productive hydrocarbons in an unproved area; (ii) to find a new commercially productive Horizon in a field previously found to be productive of hydrocarbons at another Horizon; or (iii) to significantly extend a known prospect. 20. "Farmout" shall mean an agreement whereby the owner of the leasehold or Working Interest agrees to assign his interest in certain specific acreage 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" shall mean any one of the following: (i) the expiration of the fixed term of the Partnership; (ii) the giving of notice to the Participants by the Managing General Partner of its election to terminate the affairs of the Partnership; (iii) the giving of notice by the Participants to the Managing General Partner of their similar election through the affirmative vote of Participants whose Agreed Subscriptions equal a majority of the Partnership Subscription; or (iv) the termination of the Partnership under Section 708(b)(1)(A) of the Code or the Partnership ceases to be a going concern. 22. "Horizon" shall mean a zone of a particular formation; that part of a formation of sufficient porosity and permeability to form a petroleum reservoir. 23. "Independent Expert" shall mean a person with no material relationship to the Sponsor or its Affiliates who is qualified and who is in the business of rendering opinions regarding the value of oil and gas properties based upon the evaluation of all pertinent economic, financial, geologic and engineering information available to the Sponsor or its Affiliates. 24. "Initial Closing Date" shall mean the date after the minimum Partnership Subscription has been received when subscription proceeds are first withdrawn from the escrow account. 4 25. "Intangible Drilling Costs" or "Non-Capital Expenditures" 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 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 Code and Treasury Reg. Section 1.612-4, which are generally termed "intangible drilling and development costs," including the expense of plugging and abandoning any well before a completion attempt. 26. "Interim Closing Date" shall mean those date(s) after the Initial Closing Date of the Partnership, but before the Offering Termination Date, that the Managing General Partner, in its sole discretion, applies additional Agreed Subscriptions to additional Partnership activities, including drilling activities. 27. "Investor General Partners" shall mean: (i) the persons signing the Subscription Agreement as Investor General Partners; and (ii) the Managing General Partner to the extent of any optional subscription under Section 3.03(b)(2). All Investor General Partners shall be of the same class and have the same rights. 28. "Landowner's Royalty Interest" shall mean an interest in production, or the proceeds therefrom, to be received free and clear of all costs of development, operation, or maintenance, reserved by a landowner upon the creation of an oil and gas Lease. 29. "Leases" shall mean full or partial interests in oil and gas leases, oil and gas mineral rights, fee rights, licenses, concessions, or other rights under which the holder is entitled to explore for and produce oil and/or gas, and further includes any contractual rights to acquire any such interest. 30. "Limited Partners" shall mean: (i) the persons signing the Subscription Agreement as Limited Partners; (ii) the Managing General Partner to the extent of any optional subscription under Section 3.03(b)(2); (iii) the Investor General Partners upon the conversion of their Investor General Partner Units to Limited Partner interests pursuant to Section 6.01(b); and (iv) any other persons who are admitted to the Partnership as additional or substituted Limited Partners. Except as provided in Section 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" shall mean: (i) Atlas Resources, Inc.; or (ii) any Person admitted to the Partnership as a general partner other than as an Investor General Partner pursuant to this Agreement who is designated to exclusively supervise and manage the operations of the Partnership. 32. "Managing General Partner Signature Page" shall mean an execution and subscription instrument in the form attached as Exhibit (I-A) to this Agreement, which is incorporated herein by reference. 5 33. "Net of Tax Savings Payout" shall mean the time when: (i) the cumulative credit equivalent of the Partnership's deductions for Intangible Drilling Costs and percentage depletion on the Participants' share of the Partnership's income as estimated by the Managing General Partner; plus (ii) the cumulative cash distributed to the Participants; equals 100% of the Participants' aggregate Capital Contributions. Once Net of Tax Savings Payout is reached it will not be affected by future Capital Contributions. 34. "Offering Termination Date" shall mean the date after the minimum Partnership Subscription has been received on which the Managing General Partner determines, in its sole discretion, the Partnership's subscription period is closed and the acceptance of subscriptions ceases, which shall not be later than December 31, 2000. 35. "Operating Costs" shall mean expenditures made and costs incurred in producing and marketing oil or gas 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 oil and gas; (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 such operations. Operating Costs also include reworking, workover, subsequent equipping and similar expenses relating to any well. 36. "Operator" shall mean the Managing General Partner, as operator of Partnership Wells in Pennsylvania, and the Managing General Partner or an Affiliate as Operator of Partnership Wells in other areas of the United States. 37. "Organization and Offering Costs" shall mean 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); (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. 38. "Organization Costs" shall mean all costs of organizing the offering including, but not limited to: (i) 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; 6 (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. 39. "Overriding Royalty Interest" shall mean an interest in the oil and gas produced pursuant to a specified oil and gas Lease or Leases, 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. 40. "Participants" shall mean: (i) the Managing General Partner to the extent of its optional subscription under Section 3.03(b)(2); (ii) the Limited Partners; and (iii) the Investor General Partners. 41. "Partners" shall mean: (i) the Managing General Partner; (ii) the Investor General Partners; and (iii) the Limited Partners. 42. "Partnership" shall mean Atlas America Public #9 Ltd., the Pennsylvania limited partnership formed pursuant to this Agreement. 43. "Partnership Net Production Revenues" shall mean gross revenues after deduction of the related Operating Costs, Direct Costs, Administrative Costs and all other Partnership costs not specifically allocated. 44. "Partnership Payout" shall mean the time when the Partnership's cumulative cash distributions to the Participants equal 100% of the Participants' aggregate Capital Contributions. Once Partnership Payout is reached it will not be affected by future Capital Contributions. Although the Participants receive tax benefits, the Managing General Partner will not include these in the Participant return for determining Partnership Payout. I.E., the Managing General Partner's increased revenue share after Partnership Payout will not begin until the Participant receives all of his investment back in cash excluding tax benefits. 45. "Partnership Subscription" shall mean the aggregate Agreed Subscriptions of the parties to this Agreement; provided, however, with respect to Participant voting rights under this Agreement, the term "Partnership Subscription" shall be deemed not to include the Managing General Partner's required subscription under Section 3.03(b)(1). 46. "Partnership Well" shall mean a well, some portion of the revenues from which is received by the Partnership. 47. "Person" shall mean a natural person, partnership, corporation, association, trust or other legal entity. 48. "Program" shall mean one or more limited or general partnerships or other investment vehicles formed, or to be formed, for the primary purpose of: (i) exploring for oil, gas 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 the proceeds thereof. 7 49. "Prospect" shall mean 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" with respect to 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, with respect to the Clinton/Medina geological formation and the Mississippian/Upper Devonian Sandstone reservoirs in Ohio, Pennsylvania and New York, "Prospect" shall be deemed the drilling or spacing unit. 50. "Proved Developed Oil and Gas Reserves" shall mean 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. 51. "Proved Reserves" shall mean 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) 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. (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"; 8 (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. 52. "Proved Undeveloped Reserves" shall mean 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. 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. 53. "Roll-Up" shall mean 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 term of existence of the Partnership; (c) the Managing General Partner's compensation; and (d) the Partnership's investment objectives. 54. "Roll-Up Entity" shall mean a partnership, trust, corporation or other entity that would be created or survive after the successful completion of a proposed roll-up transaction. 55. "Sales Commissions" shall mean all underwriting and brokerage discounts and commissions incurred in the sale of Units in the Partnership payable to registered broker/dealers, but excluding the Dealer-Manager fee, a .5% reimbursement of marketing expenses, and a .5% reimbursement for bona fide accountable due diligence expenses. 56. "Selling Agents" shall mean those broker/dealers selected by the Dealer-Manager which will participate in the offer and sale of the Units. 9 57. "Sponsor" shall mean 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. 58. "Subscription Agreement" shall mean an execution and subscription instrument in the form attached as Exhibit (I-B) to this Agreement, which is incorporated herein by reference. 59. "Tangible Costs" or "Capital Expenditures" shall mean those costs associated with the drilling and completion of oil and gas wells which are generally accepted as capital expenditures pursuant to the provisions of the Internal Revenue Code. This includes all costs of equipment, parts and items of hardware used in drilling and completing a well, and those items necessary to deliver acceptable oil and gas production to purchasers to the extent installed downstream from the wellhead of any well and which are required to be capitalized pursuant to applicable provisions of the Code and regulations promulgated thereunder. 60. "Tax Matters Partner" shall mean the Managing General Partner. 61. "Units" or "Units of Participation" shall mean the Limited Partner interests and the Investor General Partner interests purchased by Participants in the Partnership under the provisions of Section 3.03 and its subsections. 62. "Working Interest" shall mean an interest in an oil and gas leasehold which is subject to some portion of the cost of development, operation, or maintenance. 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 Section 3.03(b)(2). Limited Partners and Investor General Partners, including Affiliates of the Managing General Partner, shall serve as Participants. 3.02. PARTICIPANTS. 3.02(a). LIMITED PARTNER AT FORMATION. Atlas America, Inc., as Original Limited Partner, has acquired one Unit and has made a Capital Contribution of $100. Upon 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 the 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 Agreed Subscriptions for Units are 10 accepted by the Managing General Partner if, after the admission of the additional Participants, the Agreed Subscriptions of all Participants do not exceed the number of Units set forth in Section 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 by an independent interest bearing escrow holder and shall not be released to the Partnership until the receipt of the minimum Partnership Subscription in Section 3.03(c)(2). Thereafter, subscriptions may be paid directly to the Partnership account. 3.02(d). DURATION OF THE OFFERING AND MINIMUM CAPITALIZATION. 3.02(d)(1). DURATION OF OFFERING. The offering of Units shall be terminated not later than the earlier of: (i) December 31, 2000; or (ii) at the time the Agreed Subscriptions for the maximum Partnership Subscription set forth in Section 3.03(c)(1) shall have been received and accepted by the Managing General Partner. The offering may be terminated earlier at the option of the Managing General Partner. 3.02(d)(2). MINIMUM CAPITALIZATION. If at the time of termination Agreed Subscriptions for fewer than 100 Units have been received and accepted, then all monies deposited by subscribers shall be promptly returned to them. They shall receive interest earned thereon from the date the monies were deposited in escrow through the date of refund. 3.03. SUBSCRIPTIONS TO THE PARTNERSHIP. 3.03(a). SUBSCRIPTIONS BY PARTICIPANTS. 3.03(a)(1). AGREED SUBSCRIPTION. A Participant's Agreed Subscription to the Partnership shall be the amount so designated on his Subscription Agreement. 3.03(a)(2). SUBSCRIPTION PRICE AND MINIMUM AGREED SUBSCRIPTION. The subscription price of a Unit in the Partnership shall be $10,000, payable as set forth in this Agreement. The minimum Agreed Subscription per Participant shall be one Unit ($10,000); however, the Managing General Partner, in its discretion, may accept one-half Unit ($5,000) subscriptions. Larger Agreed Subscriptions shall be accepted in $1,000 increments. 3.03(a)(3). 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). SUBSCRIPTIONS BY MANAGING GENERAL PARTNER. 3.03(b)(1). MANAGING GENERAL PARTNER'S REQUIRED SUBSCRIPTION. The Managing General Partner, as a general partner and not as a Participant, shall: (i) contribute to the Partnership the Leases which will be drilled by the Partnership on the terms set forth in Section 4.01(a)(4); and (ii) pay the costs charged to it as set forth in this Agreement. 3.03(b)(2). MANAGING GENERAL PARTNER'S OPTIONAL ADDITIONAL SUBSCRIPTION. In addition to the Managing General Partner's required subscription under Section 3.03(b)(1), the Managing General Partner may subscribe to up to 10% of the Units on the same basis as a Participant may subscribe to Units under the provisions of Section 3.03(a) and its subsections, and, subject to the limitations on voting rights set forth in Section 4.03(c)(3), to that extent shall be deemed a Participant in the Partnership for all purposes under this Agreement. 11 Notwithstanding the foregoing, Selling Agents, and the Managing General Partner, its officers, directors, and Affiliates shall not be required to pay the Dealer-Manager fee, Sales Commissions, the .5% reimbursement of marketing expenses, and the .5% reimbursement of the Selling Agents' bona fide accountable due diligence expenses. Also, Registered Investment Advisors and their clients may subscribe by paying only the Dealer-Manager fee and not the Sales Commissions, the .5% reimbursement of marketing expenses, and the .5% reimbursement of the Selling Agents' bona fide accountable due diligence expenses. In both cases their Agreed Subscriptions shall be treated by the Partnership as though they had paid $10,000 per Unit for purposes of: (i) their voting rights under this Agreement; (ii) the Roll-Up provisions under Section 4.03(d)(16) and its subsections; (iii) their allocations under Section 5.01(c)(1); and (iv) their presentment rights under Section 6.04 and its subsections. 3.03(b)(3). 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 subscription under Section 3.03(b)(1); and (ii) may be amended to reflect the amount of any optional subscription under Section 3.03(b)(2). 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 PARTNERSHIP SUBSCRIPTION. 3.03(c)(1). MAXIMUM PARTNERSHIP SUBSCRIPTION. The maximum Partnership Subscription excluding the Managing General Partner's required subscription under Section 3.03(b)(1) may not exceed $15,000,000 (1,500 Units). 3.03(c)(2). MINIMUM PARTNERSHIP SUBSCRIPTION. The minimum Partnership Subscription shall equal at least $1,000,000 (100 Units). The Managing General Partner, its officers, directors, and Affiliates may purchase up to 10% of the Partnership Subscription, none of which will be applied to satisfy the $1,000,000 minimum. The Partnership shall begin drilling operations after the receipt of the minimum Partnership Subscription. 3.03(d). ACCEPTANCE OF SUBSCRIPTIONS. 3.03(d)(1). DISCRETION BY THE MANAGING GENERAL PARTNER. Acceptance of subscriptions shall be 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. A Participant's subscription to the Partnership and the Managing General Partner's acceptance of the subscription shall be evidenced by the execution of a Subscription Agreement by the Participant and by the Managing General Partner. Agreed Subscriptions shall be accepted or rejected by the Partnership within 30 days of their receipt. If an Agreed Subscription is rejected, then all funds shall be returned to the subscriber immediately. 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 escrow of Participants' funds to the Partnership; and (ii) after the close of the escrow account not later than the last day of the calendar month in which their Agreed Subscriptions were accepted by the Partnership. 12 3.04. CAPITAL CONTRIBUTIONS. 3.04(a). PARTICIPANT CAPITAL CONTRIBUTIONS. Each Participant shall make a Capital Contribution to the Partnership equal to the sum of: (i) the Agreed Subscription of the Participant; and (ii) in the case of Investor General Partners, but not the Limited Partners, the additional Capital Contributions required in Section 3.05(b)(2). Participants shall not be required to restore any deficit balances in their Capital Accounts except as set forth in Section 5.03(h). 3.04(b). ADDITIONAL MANAGING GENERAL PARTNER CAPITAL CONTRIBUTIONS. 3.04(b)(1). ADDITIONAL CAPITAL CONTRIBUTIONS OF THE MANAGING GENERAL PARTNER. In addition to any Capital Contribution required of the Managing General Partner as provided in Section 3.03(b)(1) and any optional Capital Contribution as a Participant as provided in Section 3.03(b)(2), the Managing General Partner shall further contribute cash sufficient to pay all costs charged to it under this Agreement to the extent the costs exceed: (i) its Capital Contribution pursuant to Section 3.03(b); and (ii) its share of undistributed revenues. These Capital Contributions shall be paid by the Managing General Partner at the time the costs are required to be paid by the Partnership, but no later than December 31, 2001. 3.04(b)(2). MINIMUM AMOUNT OF MANAGING GENERAL PARTNER'S REQUIRED CONTRIBUTION. The Managing General Partner is required to: (i) make aggregate Capital Contributions to the Partnership (including Leases contributed pursuant to Section 3.03(b)(1)) of not less than 25% of all Capital Contributions to the Partnership; and (ii) maintain a minimum Capital Account balance equal to 1% of total positive Capital Account balances for the Partnership. 3.04(b)(3). UPON 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 upon 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 its interest in the Partnership is liquidated or, if later, within 90 days after the date of such liquidation. 3.04(b)(4). INTEREST FOR CONTRIBUTIONS. The interest of the Managing General Partner in the capital and revenues of the Partnership is in consideration for, and is the only consideration for, its Capital Contribution to the Partnership. 3.04(c). LIMITATION ON AMOUNT OF REQUIRED CAPITAL CONTRIBUTIONS OF LIMITED PARTNERS. In no event shall a Limited Partner be required to make contributions to the Partnership greater than his required Capital Contribution under Section 3.04(a). 13 3.05. PAYMENT OF SUBSCRIPTIONS. 3.05(a). MANAGING GENERAL PARTNER'S SUBSCRIPTIONS. The Managing General Partner shall: (i) contribute to the Partnership the Leases pursuant to Section 3.03(b)(1); (ii) pay the costs charged to it when incurred by the Partnership, subject to Section 3.04(b)(1); and (iii) pay any optional subscription under Section 3.03(b)(2) in the same manner as provided for the payment of Participant subscriptions. 3.05(b). PARTICIPANT SUBSCRIPTIONS AND ADDITIONAL CAPITAL CONTRIBUTIONS OF THE INVESTOR GENERAL PARTNERS. 3.05(b)(1). PAYMENT OF AGREED SUBSCRIPTIONS. A Participant shall pay his Agreed Subscription 100% in cash at the time of subscribing. A Participant shall receive interest on his Agreed Subscription up until the Offering Termination Date. 3.05(b)(2). ADDITIONAL REQUIRED CAPITAL CONTRIBUTIONS OF THE INVESTOR GENERAL PARTNERS. Investor General Partners are obligated to make Capital Contributions to the Partnership when called by the Managing General Partner (in addition to their Agreed Subscriptions) 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 interests pursuant to Section 6.01(b). 3.05(b)(3). DEFAULT PROVISIONS. The failure of an Investor General Partner to timely make a required additional Capital Contribution pursuant to this section results in his personal liability to the other Investor General Partners for the amount in default. The remaining Investor General Partners, pro rata, must pay the defaulting Investor General Partner's share of Partnership liabilities and obligations. 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 directly from the Partnership 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 shall have 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 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, except as provided in Sections 4.01, 4.02, 4.04, 4.05 and 4.06 of this Agreement. 3.06(b). SPECIAL ACCOUNT AFTER THE RECEIPT OF THE MINIMUM PARTNERSHIP SUBSCRIPTION. Following the receipt of the minimum Partnership Subscription, 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 may 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 Section 3.06(c)(2); 14 (iii) multi-tier arrangements meeting the requirements of Section 4.03(d)(15); (iv) investments involving less than 5% of the Partnership Subscription 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, in such instances duplicative fees and expenses shall be prohibited. 3.06(c)(2). PERMISSIBLE INVESTMENTS PRIOR TO INVESTMENT IN PARTNERSHIP ACTIVITIES. After the Offering Termination 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 oil and gas industry, subject to the terms and conditions set forth below. 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 unless the acquisition is made after a well has been drilled to a depth sufficient to indicate that such an 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 Section 4.03(d) and its subsections, the acquisitions of Leases or other property may be made under any terms and obligations, including: (i) any limitations as to the Horizons to be assigned to the Partnership; and (ii) 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) acquired from the Managing General Partner or its Affiliates; and (ii) credited towards the Managing General Partner's required Capital Contribution set forth in Section 3.03(b)(1) at the Cost of the Lease, unless the Managing General Partner shall have cause to believe that Cost is materially more than the fair market value of the property, in which case the credit for the contribution will be made at a price not in excess of the fair market value. A determination of fair market value must be: (i) supported by an appraisal from an Independent Expert; and (ii) maintained in the Partnership's records for six years along with associated supporting information. 4.01(a)(5). THE MANAGING GENERAL PARTNER, OPERATOR OR THEIR AFFILIATES' RIGHTS IN THE REMAINDER INTERESTS. 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: 15 (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. 4.01(a)(6). NO BREACH OF DUTY. Subject to the provisions of Section 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 the Managing General Partner, the Operator or their Affiliates 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 Lease interests 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 the Leases acquired by the Partnership 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 Section 4.03 and its subsections, and to any authority which may be granted the Operator under Section 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: 16 (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; (b) the furnishing of equipment, facilities, supplies and material, services, and personnel; and (c) the exercise of any options, elections, or decisions under any such agreements; (iii) the exercise, on behalf of the Partnership or the parties, in such manner 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 such 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) such excess liability insurance as to bodily injury and property damage with combined limits of $50,000,000, during drilling operations and $10,000,000 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 an accident. The excess liability insurance shall be in place and effective no later than the date drilling operations begin and shall continue until the Investor General Partners are converted to Limited Partners, at which time the Partnership shall have the benefit of the Managing General Partner's $11,000,000 liability insurance on the same basis as the Managing General Partner and its 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 such borrowings or loans used initially to finance such operations or activities; 17 (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 Section 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 and absolute 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 other incurring of legal expense; and (c) the settlement of claims and litigation; (xi) the operation of producing wells drilled on the Leases owned by the Partnership, 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 pursuant to 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 related to it. The 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 the competitive rates or duplicative of any consideration or reimbursements received pursuant to 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 Section 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 Section 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 will be drilled pursuant to the Drilling and Operating Agreement on a Cost plus 15% basis. 18 The Managing General Partner or its Affiliates, as drilling contractor, is subject to the following prohibitions: (i) it may not receive a rate that is not competitive with the rates charged by unaffiliated contractors in the same geographic region; (ii) it may not enter into a turnkey drilling contract with the Partnership; (iii) it may not profit by drilling in contravention of its fiduciary obligations to the Partnership; and (iv) it may not 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 party to this Agreement makes, constitutes and 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 or other instruments required or 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. 4.02(d)(2)(b). FURTHER ACTION. Each party to this Agreement 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. Each party acknowledges that the power of attorney granted under this section: (i) is a special power of attorney coupled with an interest and is irrevocable; and (ii) shall survive the assignment by a party of the whole or a portion of his interest in the Partnership; except when the assignment is of the party's entire interest in the Partnership and the purchaser, transferee or assignee of the interest, with the consent of the Managing General Partner, 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 to the Partnership the funds necessary pursuant to Section 4.03(d)(8)(b), although they are not obligated to advance the funds to the Partnership. 19 4.02(e)(1)(b). LIMITATION ON BORROWING. The 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 Subscription. 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 pursuant to 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 Participants of any partnership administrative proceedings commenced by the Internal Revenue Service, and thereafter shall furnish all 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 such 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 hereof) with the Internal Revenue Service pursuant to Section 6224(b) of the Code if necessary to perfect the waiver of rights under this subsection 4.02(f)(4). 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 Pennsylvania 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 amount of their agreed Capital Contributions unless: (i) they also subscribe to the Partnership as Investor General Partners; or (ii) in the case of the Managing General Partner if 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 2000 calendar year, the Partnership shall provide each Participant an annual report within 120 days after the close of the calendar year, and beginning with the 2001 20 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 in accordance with generally accepted accounting principles 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 unaccountable, fixed payment reimbursements for Administrative Costs and Operating Costs, paid by the Partnership, or indirectly on behalf of the Partnership, to the Managing General Partner, the Operator and their Affiliates. In addition, Participants shall be provided the percentage that the annual unaccountable, fixed fee reimbursement for Administrative Costs bears to annual Partnership revenues. (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 whether each of the wells has or has not been completed), and a statement of the cost of each well completed or abandoned. Justification must be included for wells abandoned after production has begun. (v) A description of all farmins and joint ventures, made during the period of the report, including the Managing General Partner's justification for the arrangement and 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. 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. Annually, beginning January 1, 2002 the Partnership shall provide to each Participant the following: (i) a computation of the total oil and gas Proved Reserves of the Partnership; 21 (ii) a computation of the present worth of the reserves determined using a discount rate of 10%, a constant price for the oil and basing the price of gas upon the existing 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 there is an event which leads to the reduction of the reserves of the Partnership of 10% or more, excluding reduction as a result of normal production, sales of reserves or product price changes, then a computation and estimate must be sent to each Participant within 90 days. 4.03(b)(4). COST OF REPORTS. The cost of all reports described herein 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 records of the Partnership. The Participant may inspect and copy any of the records after giving adequate notice 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 shall maintain and preserve during the term of the Partnership and for six years thereafter all accounts, books and other relevant documents which includes: (i) a record that a Participant meets the suitability standards established in connection with an investment in the Partnership; and (ii) of fair market value as set forth in Section 4.01(a)(4). 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") shall be maintained as a part of the books and records of the Partnership and shall be available for inspection by any Participant or his designated agent at the home office of the Partnership upon the request of the Participant; (ii) the Participant List shall be updated at least quarterly to reflect changes in the information contained therein; (iii) a copy of the Participant List shall be mailed to any Participant requesting the Participant List within 10 days of the written request. The copy of the Participant List shall be printed in alphabetical order, on white paper, and in a readily readable type size (in no event smaller than 10-point type). A reasonable charge for copy work shall 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 22 that the actual purpose and reason for the requests 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 thereof, 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 shall 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 hereunder 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 Section 4.03(b) with: (i) the California Commissioner of Corporations; and (ii) 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 Agreed Subscriptions equal 10% or more of the Partnership Subscription for any matters for which Participants may vote. The call for a meeting by Participants shall be deemed to have been made upon receipt by the Managing General Partner of a written request from holders of the requisite percentage of Agreed Subscriptions 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 Securities and Exchange Commission 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 Agreed Subscriptions equal 10% or more of the Partnership Subscription, 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 Agreed Subscriptions equal a majority of the Partnership Subscription 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; 23 (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 upon 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; 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 Section 4.03(c)(2)(ii) and (iv) above; or (ii) regarding 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 Section 4.03(c), except for the special voting rights granted Participants under Section 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 Pennsylvania 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 upon the vote of Limited Partners whose Agreed Subscriptions equal a majority of the Agreed Subscriptions 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 the Participants 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 oil, gas 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 24 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 if the following 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. With respect to an oil and gas Prospect located in Ohio, Pennsylvania and New York on which a well will be drilled by the Partnership to test the Clinton/Medina geological formation or the Mississippian/Upper Devonian Sandstone reservoirs, a Prospect shall be deemed to consist of the drilling and spacing unit if it meets the test in the preceding sentence. Within five years of the drilling of the Partnership Well neither the Managing General Partner nor its Affiliates may drill any well in the Clinton/Medina geological formation within 1,650 feet of an existing Partnership Well in Pennsylvania or within 1,000 feet of an existing Partnership Well in Ohio or in the Mississippian/Upper Devonian Sandstone reservoirs within 1,000 feet of an existing Partnership Well. If the Partnership abandons its interest in a well, then this restriction will continue for one year following the abandonment. If the area constituting the Partnership's Prospect is subsequently enlarged to encompass any area wherein 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 which are attributable to the separate property interest, then the separate property interest or a portion thereof shall be sold, transferred or conveyed to the Partnership as set forth in Sections 4.01(a)(4), 4.03(d)(1) and 4.03(d)(2). Notwithstanding the foregoing, Prospects in the Clinton/Medina geological formation or the Mississippian/Upper Devonian Sandstone reservoirs 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. With respect to its retained interest the Managing General Partner shall not Farmout a Lease for the primary purpose of avoiding payment of its costs relating to drilling the Lease. 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). NO SALE OF LEASES TO THE MANAGING GENERAL PARTNER. The Managing General Partner and its Affiliates shall not purchase any producing or non-producing oil and gas properties from the Partnership. 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, the following conditions shall apply: 25 (i) 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) does not currently own property in the Prospect separately from the Partnership, then neither the Managing General Partner nor the Affiliate shall be permitted to purchase an interest in the Prospect; and (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 Partnership shall not purchase properties from or sell properties to any other Affiliated partnership. This prohibition, however, shall not apply to joint ventures among Affiliated partnerships, provided that: (i) 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 (ii) 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 Agreed Subscriptions equal a majority of the Partnership Subscription. 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 oil and gas 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 therefore 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 are cancelable without penalty upon 60 days written notice by Participants whose Agreed Subscriptions equal a majority of the Partnership Subscription. 26 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 any Affiliate. 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 from third-party lenders may be reimbursed to the Managing General Partner or the Affiliate. 4.03(d)(9). NO FARMOUTS. The Partnership shall not Farmout its Leases. 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 Section 4.06(c), all benefits from marketing arrangements or other relationships affecting the property of the Managing General Partner or its Affiliates and the Partnership shall be fairly and equitably apportioned according to the respective interests of each in the property. The Managing General Partner shall treat all wells in a geographic area equally concerning to whom and at what price the Partnership's gas will be sold and to whom and at what price the gas of other oil and gas Programs which the Managing General Partner has sponsored or will sponsor will be sold. The Managing General Partner calculates a weighted average selling price for all the gas sold in a geographic area by taking all money received from the sale of all the gas sold to its customers in a geographic area and dividing by the volume of all gas sold from the wells in that geographic area. 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 and for a business purpose. 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 which would circumvent these guidelines. 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 expenses, 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. 27 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 Securities and Exchange Commission 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 by an independent petroleum consultant, 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; (ii) remaining as Participants in the Partnership and preserving their interests therein on the same terms and conditions as existed previously; or (iii) receiving cash in an amount equal to the Participants' pro rata share of the appraised value of the net assets of the Partnership. 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 Sections 4.03(c)(1) and 4.03(c)(2) of this Agreement. 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 which 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 will be less than those provided for under Sections 4.03(b)(5), 4.03(b)(6) and 4.03(b)(7) of this Agreement. 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 Agreed Subscriptions equal 75% of the Partnership Subscription 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 Agreed Subscriptions equal 75% of the Partnership Subscription. 4.03(d)(17). DISCLOSURE OF BINDING AGREEMENTS. Any agreement or arrangement which binds the Partnership must be disclosed in the Prospectus. 28 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: (i) pursuant to transactions that are fair and reasonable; nor (ii) 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. Atlas shall serve as the Managing General Partner of the Partnership until either: (i) it is removed pursuant to Section 4.04(a)(3); or (ii) it withdraws pursuant to Section 4.04(a)(3)(f). 4.04(a)(2). COMPENSATION OF MANAGING GENERAL PARTNER. In addition to the compensation set forth in Sections 4.01(a)(4) and 4.02(d)(1), the Managing General Partner shall receive the compensation set forth in Sections 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 Subscription and out of Partnership revenues. 4.04(a)(2)(b). DIRECT COSTS. The Managing General Partner 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 an unaccountable, fixed payment reimbursement for its Administrative Costs of $75 per well per month. The unaccountable, 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 plugged or abandoned wells. 4.04(a)(2)(d). GAS GATHERING. A limited partnership in which a subsidiary of Atlas America, Inc. serves as general partner, Atlas Pipeline Partners, L.P., shall receive a gathering fee for gathering, compressing and transporting the Partnership's gas at a competitive rate. 4.04(a)(2)(e). DEALER-MANAGER FEE. Subject to Section 3.03(b)(2), the Dealer-Manager shall receive on each Unit sold to investors: (i) a 2.5% Dealer-Manager fee; (ii) a 7% Sales Commission; 29 (iii) a .5% reimbursement of marketing expenses; and (iv) a .5% reimbursement of the Selling Agents' bona fide accountable 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 Section 4.03(d)(7) with the Partnership and shall be entitled to compensation pursuant to such 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 upon 60 days advance written notice to the outgoing Managing General Partner, by the affirmative vote of Participants whose Agreed Subscriptions equal a majority of the Partnership Subscription. If Participants vote to remove the Managing General Partner from the Partnership, then Participants must elect by an affirmative vote of Participants whose Agreed Subscriptions equal a majority of the Partnership Subscription either: (i) to terminate, dissolve and wind up the Partnership; or (ii) to continue as a successor limited partnership under all the terms of this Partnership Agreement, as provided in Section 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 Agreed Subscriptions equal a majority of the Partnership Subscription 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 the Managing General Partner's 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 recovery of oil and gas reserves, but not less than that utilized in the most recent presentment offer, 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 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 must 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 the Partnership 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 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. The removed Managing General Partner, at the time of its removal shall cause, to the extent it is legally possible, its successor to be transferred or assigned all 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 its rights, obligations and interests as Managing General Partner of the Partnership in any such contract to terminate at the time of its removal. 30 Notwithstanding any other provision in this Agreement, the Partnership or the successor Managing General Partner shall not: (i) be a party to any gas supply agreement that the Managing General Partner or its Affiliates enters into with a third-party; or (ii) have any rights pursuant to such gas supply agreement. Further, the Partnership or the successor Managing General Partner shall not receive any interest in the Managing General Partner's and its Affiliates' 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 of the Partnership and the Partnership's primary drilling activities, the Managing General Partner may voluntarily withdraw as Managing General Partner upon 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 Section 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 Section 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). THE MANAGING GENERAL PARTNER'S RIGHT TO WITHDRAW PROPERTY INTEREST. The Managing General Partner has the right at any time to withdraw a property interest held by the Partnership in the form of a Working Interest in the Partnership Wells equal to or less than its respective interest in the revenues of the Partnership pursuant to the conditions set forth in Section 6.03. If the Managing General Partner withdraws an interest, 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 a partial withdrawal of its interests including insuring that Participants do not have a greater amount of Direct Costs or Administrative Costs allocated to them. 4.04(a)(4). REMOVAL OF OPERATOR. The Operator may be removed and a new Operator may be substituted at any time upon 60 days advance written notice to the outgoing Operator by the Managing General Partner acting on behalf of the Partnership upon the affirmative vote of Participants whose Agreed Subscriptions equal a majority of the Partnership Subscription. The Operator shall not be removed until a substituted Operator has been selected by an affirmative vote of Participants whose Agreed Subscriptions equal a majority of the Partnership Subscription 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 Participants which arises out of any action or inaction by them 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. 31 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 tangible net assets of the Partnership; (ii) revenues from operations; and (iii) any insurance proceeds. 4.05(a)(3). STANDARDS FOR SECURITIES LAW INDEMNIFICATION. Notwithstanding anything to the contrary contained in the above, the Managing General Partner, the Operator, and their Affiliates and any person acting as a broker/dealer 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 Securities and Exchange Commission, the Massachusetts Securities Division, and the position of any state securities regulatory authority in which plaintiffs claim they were offered or sold Partnership 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 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 32 (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 the Managing General Partner, the Operator, or their Affiliates could not be indemnified pursuant to Sections 4.05(a)(1) and 4.05(a)(2). 4.05(b). LIABILITY OF PARTNERS. Pursuant to the Pennsylvania 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 hereby agree that each shall be solely and individually responsible only for his pro rata share of the liabilities and obligations of the Partnership. In addition, the Managing General Partner agrees to use its corporate assets and not the assets of the Partnership 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 and does hereby 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 the assets and revenues of the Partnership; and (iii) last, by the Managing General Partner as provided in Sections 3.05(b)(2) and (3) and 4.05(b). No Limited Partner shall be required to reimburse the Managing General Partner, the Operator, or 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 Partnership management; 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 the Managing General Partner, the Operator, or their Affiliates, which is authorized by this Agreement to be entered into or taken with such party 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 OIL AND GAS 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 oil and gas business. This includes without limitation, the evaluation, acquisition and sale of producing and nonproducing Leases, and the exploration for and production of oil, gas, and other minerals. The Managing General Partner is required to devote only so much of its time as 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: 33 (i) may continue its 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) may reserve partial interests in Leases being assigned to the Partnership or any other interests not expressly prohibited by this Agreement; (iii) may deal with the Partnership as independent parties or through any other entity in which they may be interested; (iv) may conduct business with the Partnership as set forth in this Agreement; and (v) may 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 any such operations in which they may be interested or share in any profits or other benefits therefrom. However, except as otherwise provided in this Agreement, the Managing General Partner and any of 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 GAS CONTRACTS OR PIPELINES AND GATHERING SYSTEMS. Notwithstanding any other provision in this Agreement, the Partnership shall not: (i) be a party to any gas supply agreement that the Managing General Partner, the Operator, or their Affiliates enter into with a third-party; or (ii) have any rights pursuant to such gas supply agreement. Further, the Partnership shall not receive any interest in the Managing General Partner's, the Operator's, and their Affiliates' pipeline or gathering system 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 shall be charged and credited to the Managing General Partner and the Participants as set forth in this Section 5.01 and its subsections. 5.01(a). COSTS. Costs shall be charged as set forth below. 5.01(a)(1). ORGANIZATION COSTS. Organization Costs shall be charged 100% to the Managing General Partner. For purposes of sharing in revenues pursuant to Section 5.01(b)(4), the Managing General Partner shall be credited with Organization Costs paid by the Managing General Partner up to and including 4.5% of the Partnership Subscription. Any Organization Costs in excess of 4.5% of the Partnership Subscription shall be charged 100% to the Managing General Partner without recourse to the Partnership and the Managing General Partner shall not be credited with these amounts towards its required Capital Contribution. 34 5.01(a)(2). DEALER-MANAGER FEE, SALES COMMISSIONS, REIMBURSEMENT OF MARKETING EXPENSES, AND REIMBURSEMENT FOR BONA FIDE ACCOUNTABLE DUE DILIGENCE EXPENSES. The Dealer-Manager fee, Sales Commissions, and reimbursement for bona fide accountable due diligence expenses payable to the Dealer-Manager shall be charged 100% to the Participants. The reimbursement of marketing expenses payable to the Dealer-Manager shall be charged 100% to the Managing General Partner. 5.01(a)(3). INTANGIBLE DRILLING COSTS. Intangible Drilling Costs shall be charged 100% to the Participants. 5.01(a)(4). TANGIBLE COSTS. Tangible Costs shall be charged 100% to the Managing General Partner. 5.01(a)(5). 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)(6). ALLOCATION OF INTANGIBLE DRILLING COSTS AT PARTNERSHIP CLOSINGS. Intangible Drilling 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 proceeds of each Partnership closing will be used to pay the costs of drilling different wells, each Participant will pay the same amount of the costs regardless of when he subscribes. 5.01(a)(7). LEASE COSTS. The Leases shall be contributed to the Partnership by the Managing General Partner as set forth in Section 4.01(a)(4). 5.01(b). REVENUES. Revenues of the Partnership from all sources and wells shall be commingled and credited as set forth below. 5.01(b)(1). ALLOCATION OF REVENUES UPON DISPOSITION OF PROPERTY. If the Partners' Capital Accounts are adjusted to reflect the simulated depletion of an oil or gas property of the Partnership, then the portion of the total amount realized by the Partnership upon the taxable disposition of such property that represents recovery of its simulated tax basis therein shall be allocated to the Partners in the same proportion as the aggregate adjusted tax basis of such property was allocated to such Partners (or their predecessors in interest). If the Partners' Capital Accounts are adjusted to reflect the actual depletion of an oil or gas property of the Partnership, then the portion of the total amount realized by the Partnership upon the taxable disposition of such property that equals the Partners' aggregate remaining adjusted tax basis therein shall be allocated to the Partners in proportion to their respective remaining adjusted tax bases in such 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 such time. Finally, any excess shall be credited to the parties in accordance with the sharing ratios provided in Section 5.01(b)(4), below. In the event of a sale of developed oil and gas properties with equipment thereon, the Managing General Partner may make any reasonable allocation of proceeds between the equipment and the Leases. 5.01(b)(2). INTEREST. Interest earned on Agreed Subscriptions before the Offering Termination Date pursuant to Section 3.05(b)(1) shall be credited to the accounts of the respective subscribers who paid the subscriptions to the Partnership and paid approximately eight weeks after the Offering Termination Date. After the Offering Termination Date and until proceeds from the offering are invested in the Partnership's oil and gas operations, any interest income from temporary investments shall be allocated pro rata to the Participants providing the Agreed Subscriptions. All other interest income, including interest earned on the deposit of production revenues, shall be credited as provided in Section 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 Section 5.01(b)(4)(a), all other revenues of the Partnership shall be credited as follows: before Net of Tax Savings Payout and Partnership Payout the Participants and the Managing General Partner shall share in 35 Partnership revenues in the same percentage as their respective Capital Contribution bears to the total Partnership Capital Contributions. For example, if the Managing General Partner contributes 25% of the total Partnership Capital Contributions and the Participants contribute 75% of the total Partnership Capital Contributions, then the Managing General Partner will receive 25% of the Partnership revenues and the Participants will receive 75% of the Partnership revenues. After Net of Tax Savings Payout the Managing General Partner shall receive an additional 6.5% of the Partnership revenues, and after Partnership Payout the Managing General Partner shall receive an additional 8.5% of the Partnership revenues for a total additional amount of 15% of Partnership revenues. In the above example, after Net of Tax Savings Payout but before Partnership Payout the Managing General Partner would receive 31.5% of the Partnership revenues and the Participants would receive 68.5% of the Partnership revenues. After Partnership Payout the Managing General Partner would then receive 40% of the Partnership revenues and the Participants would receive 60% 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 10% of their Agreed Subscriptions in each of the first five 12-month periods of Partnership operations. The subordination shall begin with the first distribution of revenues to the Participants. The Managing General Partner, however, shall not subordinate an amount greater than 50% of its share of Partnership Net Production Revenues (I.E., net of the related costs as provided in Section 5.01(a)(5)) in any such distribution period. The subordination shall be determined by: (i) carrying forward to subsequent 12-month periods the amount, if any, by which cumulative cash distributions to Participants (including any subordination payments) are less than: (a) 10% of Participants' Agreed Subscriptions in the first 12-month period; (b) 20% of Participants' Agreed Subscriptions in the second 12-month period; (c) 30% of Participants' Agreed Subscriptions in the third 12-month period; or (d) 40% of Participants' Agreed Subscriptions in the fourth 12-month period (no carry forward is required if such distributions are less than 50% of Participants' Agreed Subscriptions in the fifth 12-month period because the Managing General Partner's subordination obligation terminates upon 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) 10% of Participants' Agreed Subscriptions in the first 12-month period; (b) 20% of Participants' Agreed Subscriptions in the second 12-month period; (c) 30% of Participants' Agreed Subscriptions in the third 12-month period; (d) 40% of Participants' Agreed Subscriptions in the fourth 12-month period; or (e) 50% of Participants' Agreed Subscriptions in the fifth 12-month period. The Managing General Partner's subordination obligation shall be further subject to the following conditions: (i) the subordination obligation shall be determined and paid at the time of each Partnership distribution during the subordination period, and may be prorated in the Managing General Partner's discretion (e.g. in the case of a quarterly distribution, the Managing General Partner will not have any subordination obligation if the distributions to Participants equal 2.5% or more of their Agreed Subscriptions assuming there is no subordination owed for any preceding periods); 36 (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) no subordination payments to Participants or reimbursements to the Managing General Partner shall be made after the expiration of the fifth 12-month subordination period; and (iv) 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, such distributions to the Participants and reimbursements to the Managing General Partner. 5.01(b)(5). COMMINGLING OF REVENUES FROM ALL PARTNERSHIP WELLS. The revenues from all Partnership wells will be commingled, so regardless of when a Participant subscribes he will share in the revenues from all 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 and revenues charged or credited to the Participants as a group shall be allocated among the Participants (including the Managing General Partner to the extent of any optional subscription pursuant to Section 3.03(b)(2)) in the ratio of their respective Agreed Subscriptions. 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 such 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, or in making any other allocations under this Agreement, the Managing General Partner may adopt any method of allocation which it, in its reasonable discretion, selects, if, in its sole discretion based on advice from its legal counsel or accountants, a revision to the allocations is required for the allocations to be recognized for federal income tax purposes either because of the promulgation of Treasury Regulations or other developments in the tax law. Any new allocation provisions shall be provided by an amendment to this Agreement and shall be made in a manner that would result in the most favorable aggregate consequences to the Participants 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 THE AGREEMENT. A single, separate Capital Account shall be established for each party to this Agreement, regardless of the number of interests owned by such party, the class of the interests and the time or manner in which such 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. Section 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 (without regard to Section 7701(g) of the Code) to the Partnership (net of liabilities secured by the contributed property that the Partnership is considered to assume or take subject to under Section 752 of the Code); and 37 (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. Section 1.704-l(b)(2)(iv)(g), but excluding income and gain described in Treas. Reg. Section 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 (without regard to Section 7701(g) of the Code) by the Partnership (net of liabilities secured by the distributed property that he is considered to assume or take subject to under Section 752 of the Code); (vi) allocations to him of Partnership expenditures described in Section 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. Section 1.704-l(b)(2)(iv)(g), but excluding items described in (vi) above, and loss or deduction described in Treas. Reg. Section 1.704-l(b)(4)(i) or (iii). 5.02(b)(2). EXCEPTION. If Treas. Reg. Section 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 Partners 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 Partners; 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 Section 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 such payments. 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 Section 704 and other provisions of the Code and such rules, regulations and interpretations relating thereto 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 Partners 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 Section 704(c) of the Code and the regulations thereunder) on the Partnership's books, in accordance with Treas. Reg. Section 1.704-l(b)(2)(iv)(f). 5.02(f). AMOUNT OF BOOK ITEMS. In cases where Section 704(c) of the Code or Section 5.02(e) applies, Capital Accounts shall be adjusted in accordance with Treas. Reg. Section 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 such 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. 38 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 Section 5.01(b) and its subsections. 5.03(b). TAX BASIS OF EACH PROPERTY. Subject to Section 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 upon 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 hereto 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 oil and gas property in accordance with the provisions of Section 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 Section 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 Sections 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 Partners' interests in the Partnership with respect to the credit (or the cost giving rise thereto) shall be in the same proportion as the Partners' respective distributive shares of the loss or deduction (and adjustments). Identical principles shall apply in determining the Partners' interests in the Partnership with respect to tax credits that arise from receipts of the Partnership (whether or not taxable). 5.03(h). DEFICIT CAPITAL ACCOUNTS AND QUALIFIED INCOME OFFSET. Notwithstanding any provisions of this Agreement to the contrary, an allocation of loss or deduction which would result in a Participant having a deficit Capital Account balance as of the end of the taxable year to which the allocation relates, if charged to the Participant, (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 Participant's Capital Account for depletion allowances with respect to the Partnership's oil and gas properties; (ii) allocations of loss and deduction that, as of the end of such year, reasonably are expected to be made to the Participant pursuant to Sections 704(e)(2) and 706(d) of the Code and Treas. Reg. Section 1.751-1(b)(2)(ii); and (iii) distributions that, as of the end of such year, reasonably are expected to be made to the Participant to the extent they exceed offsetting increases to the Participant'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, 39 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 such loss or deduction as quickly as possible (to the extent such chargeback does not cause or increase deficit balances in the Participants' Capital Accounts which are not required to be restored to the Partnership). Notwithstanding any provisions of this Agreement to the contrary, if a Participant 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 Participant's Capital Account which is not required to be restored to the Partnership, the Participant 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 such 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. Section 1.704-2(i). 5.03(j). PARTNERS' ALLOCABLE SHARES. Except as otherwise provided in this Agreement, each Partner's allocable share of Partnership income, gain, loss, deductions and credits shall be determined by the use of 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 Partners in the Partnership during the taxable year. In the absence of such 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 Partner's varying interest in the Partnership on each day during the taxable year. 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 Subchapter K of the Code. 5.04(c). CONTINGENT INCOME. If it is determined that any taxable income results to any party by reason of its entitlement to 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 the party. 5.04(d). Section 754 ELECTION. In the event of the transfer of an interest in the Partnership, or upon the death of an individual party hereto, or in the event of the distribution of property to any party hereto, 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 Sections 734 and 743 of the Code. 5.05. DISTRIBUTIONS. 5.05(a). IN GENERAL. 5.05(a)(1). QUARTERLY REVIEW OF ACCOUNTS. The Managing General Partner shall review the accounts of the Partnership at least quarterly to determine whether cash distributions are appropriate and the amount to be distributed, if any. 5.05(a)(2). DISTRIBUTIONS. The Partnership shall distribute funds to the Managing General Partner and the Participants allocated to their accounts which the Managing General Partner deems unnecessary to retain by the Partnership. 5.05(a)(3). NO BORROWINGS. In no event, however, shall funds be advanced or borrowed for purposes of distributions 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. 40 5.05(a)(4). DISTRIBUTIONS TO THE MANAGING GENERAL PARTNER. Cash distributions from the Partnership to the Managing General Partner shall only be made in conjunction with distributions to Participants and only out of funds properly allocated to the Managing General Partner's account. 5.05(a)(5). RESERVE. At any time after three years 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 proceeds of the sale of the production from the well up to $200 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 such costs. 5.05(b). DISTRIBUTION OF UNCOMMITTED SUBSCRIPTION PROCEEDS. Any net 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 of the Partnership, except necessary operating capital, shall be distributed pro rata to the Participants in the ratio of their Agreed Subscriptions to the Partnership, as a return of capital. The Managing General Partner shall reimburse the Participants for the selling or other offering expenses 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. Upon the winding up of the Partnership distributions shall be made as provided in Section 7.02. 5.05(d). INTEREST AND RETURN OF CAPITAL. It is agreed among the parties to this Agreement that 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 INTERESTS 6.01. TRANSFERABILITY. 6.01(a). IN GENERAL. 6.01(a)(1). CONSENT REQUIRED. In addition to other restrictions on transferability provided in this Agreement, Units in the Partnership (and any rights to income or other attributes of Units in the Partnership) shall be nontransferable except transfers to or with the written consent of the Managing General Partner. 6.01(a)(2). RIGHTS OF ASSIGNEE. Unless an assignee becomes a substituted Participant in accordance with the provisions set forth below, 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, gain, credits and cash distributions or returns of capital to which his assignor would otherwise be entitled. 6.01(b). CONVERSION OF INVESTOR GENERAL PARTNER UNITS TO LIMITED PARTNER INTERESTS. 6.01(b)(1). AUTOMATIC CONVERSION. After substantially all of the Partnership Wells have been drilled and completed the Managing General Partner shall file an amended certificate of limited partnership with the Secretary of State of the Commonwealth of Pennsylvania for the purpose of converting the Investor General Partner Units to Limited Partner interests. 6.01(b)(2). INVESTOR GENERAL PARTNERS SHALL HAVE CONTINGENT LIABILITY. Upon conversion the Investor General Partners shall be Limited Partners entitled to limited liability; however, they shall remain liable to the Partnership for any additional 41 Capital Contribution required for their proportionate share of any Partnership obligation or liability arising before the conversion of their Units as provided in Section 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 oil and gas 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 adverse material 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 interests before the reduction by giving written notice to the Managing General Partner. 6.02. SPECIAL RESTRICTIONS ON TRANSFERS. 6.02(a). IN GENERAL. Transfers are subject to the following general conditions: (i) only whole Units may be assigned unless the Participant owns less than a whole Unit, in which case his entire fractional interest must be assigned; (ii) the costs and expenses associated with the assignment must be paid by the assignor Participant; (iii) the assignment must be in a form satisfactory to the Managing General Partner; and (iv) the terms of the assignment must not contravene those of this Agreement. Transfers of interest in the Partnership are subject to the following additional restrictions set forth in Sections 6.02(a)(1) and 6.02(a)(2). 6.02(a)(1). SECURITIES LAWS RESTRICTION. Subject to transfers permitted by Section 6.04 and transfers by operation of law, no interest in the Partnership shall be sold, assigned, pledged, hypothecated or transferred unless there is either: (i) an effective registration of the Units 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 such registration and qualification are not required. Transfers are also subject to any conditions contained in the Subscription Agreement and Exhibit (B) to the Prospectus. 6.02(a)(2). TAX LAW RESTRICTIONS. Subject to transfers permitted by Section 6.04 and transfers by operation of law, no sale, exchange, transfer or assignment shall be made which, in the opinion of counsel to the Partnership, would result in: (i) the Partnership being considered to have been terminated for purposes of Section 708 of the Code; or (ii) the Partnership being treated as a "publicly-traded" partnership for purposes of Section 469(k) of the Code. 6.02(a)(3). SUBSTITUTE PARTICIPANT. 6.02(a)(3)(a). PROCEDURE TO BECOME SUBSTITUTE PARTICIPANT. An assignee of a Participant's interest in the Partnership shall become a substituted Participant entitled to all the rights of a Participant if, and only if: (i) the assignor of the Unit gives the assignee the right; 42 (ii) the Managing General Partner consents to the substitution, which consent shall be in the Managing General Partner's absolute discretion; (iii) the assignee of the Unit pays to the Partnership all costs and expenses incurred in connection with the substitution; and (iv) the assignee of the Unit executes and delivers the instruments (in form and substance satisfactory to the Managing General Partner) necessary or desirable to effect the substitution and to confirm the agreement of the assignee to be bound by all of the terms and provisions of this Agreement. 6.02(a)(3)(b). RIGHTS OF SUBSTITUTE PARTICIPANT. A substitute Participant is 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 substituted Participants. Any transfer permitted under this Agreement when the assignee does not become a substituted Participant shall be effective: (i) as of 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). TRANSFER DOES NOT RELIEVE TRANSFEROR OF CERTAIN COSTS. No transfer (including a transfer of less than all of a party's rights under this Agreement or the transfer of rights under this Agreement 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 interest so transferred, whether arising before or after the transfer. 6.02(b)(3). TRANSFER DOES NOT REQUIRE AN ACCOUNTING. No transfer of a Unit shall require an accounting by the Managing General Partner. Also, no transfer shall grant rights under this Agreement, including the exercise of any elections, as between the transferring parties and the remaining parties to this Agreement to more than one party unanimously designated by the transferees and, if he should have retained an interest under this Agreement, the transferor. 6.02(b)(4). NOTICE. Until the Managing General Partner receives a proper designation acceptable to it, the Managing General Partner shall continue to account only to the person to whom it was furnishing notices before the time pursuant to Section 8.01 and its subsections. That party shall continue to exercise all rights applicable to the entire interest previously owned by the transferor. 6.03. RIGHT OF MANAGING GENERAL PARTNER TO HYPOTHECATE AND/OR WITHDRAW 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 in the revenues of the Partnership. All repayments of such borrowings and costs and 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. In addition, subject to a required participation of not less than 1% of the Partnership Subscription, the Managing General Partner may withdraw a property interest held by the Partnership in the form of a Working Interest in the Partnership Wells equal to or less than its respective interest in the revenues of the Partnership if: 43 (i) the withdrawal is necessary to satisfy the bona fide request of its creditors; or (ii) the withdrawal is approved by Participants whose Agreed Subscriptions equal a majority of the Partnership Subscription. 6.04. PRESENTMENT. 6.04(a). IN GENERAL. Participants shall have the right to present their interests to the Managing General Partner subject to the conditions and limitations set forth in this section. A Participant, however, is not obligated to present his Units for repurchase. The Managing General Partner shall not be obligated to purchase more than 5% of the Units in any calendar year and shall not purchase less than one Unit of a Participant's interests in the Partnership unless such lesser amount represents the entire amount of the Participant's interest. The Managing General Partner may waive these limitations in its sole discretion other than the limitation that it shall not purchase more than 5% of the Units in any calendar year. A Participant may present his Units in writing to the Managing General Partner every year beginning in 2005 subject to the following conditions: (i) the presentment must be made within 120 days of the reserve report set forth in Section 4.03(b)(3); (ii) in accordance with Treas. Reg. Section 1.7704-1(f), the repurchase 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 repurchase right; and (iii) the repurchase shall not be considered effective until the payment has been made to the Participant in cash. 6.04(b). REQUIREMENT FOR INDEPENDENT PETROLEUM CONSULTANT. The amount attributable to Partnership reserves shall be determined based upon 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. In making this estimate, the Managing General Partner shall use the following terms: (i) a discount rate equal to 10%; (ii) a constant price for the oil; and (iii) base the price of gas upon the existing gas contracts at the time of the repurchase. The calculation of the repurchase price shall be as set forth in Section 6.04(c). 6.04(c). CALCULATION OF PRESENTMENT PRICE. The presentment price shall be based upon the Participant's share of the net assets and liabilities of the Partnership and allocated pro rata to each Participant based upon his Agreed Subscription. 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 Section 6.04(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, not separately specified above, determined in accordance with standard industry valuation procedures. There shall be deducted from the foregoing sum the following items: (i) an amount equal to all debts, obligations, and other liabilities, including accrued expenses; and 44 (ii) any distributions made to the Participants between the date of the request and the actual payment. However, if any cash distributed was derived from the sale, after the presentment request, of oil, gas or other mineral production, or of a producing property owned by the Partnership, for purposes of determining the reduction of the presentment price, the distributions shall 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. 6.04(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 Participants 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 request for repurchase; and (ii) any of the following occurring before payment of the presentment price to the selling Participants: (a) changes in well performance; (b) increases or decreases in the market price of oil, gas, or other minerals; (c) revision of 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. 6.04(e). SELECTION BY LOT. If less than all interests presented at any time are to be purchased, then the Participants whose interests are to be purchased will be selected by lot. The Managing General Partner's obligation to purchase interests presented may be discharged for its benefit by a third party or an Affiliate. The interests of the selling Participant will be transferred to the party who pays for it. A selling Participant will be required to deliver an executed assignment of his interest, together with such other documentation as the Managing General Partner may reasonably request. 6.04(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 obligations under this section. 6.04(g). SUSPENSION OF PRESENTMENT FEATURE. The Managing General Partner may suspend this presentment feature by so notifying Participants at any time if: (i) it does not have sufficient cash flow; or (ii) it 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 repurchased Units for its own account and not for resale. 45 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 hereinafter set forth. 7.01(b). TERMINATION. The Partnership shall terminate following: (i) the occurrence of a Final Terminating Event; or (ii) upon the occurrence of any event which under the Pennsylvania Revised Uniform Limited Partnership Act causes the dissolution of a limited partnership. 7.01(c). CONTINUANCE OF PARTNERSHIP EXCEPT UPON FINAL TERMINATING EVENT. Except upon 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 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 partnerships and the parties to the successor limited partnerships. 7.02. DISSOLUTION AND WINDING UP. 7.02(a). FINAL TERMINATING EVENT. Upon 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 assets of the Partnership. 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 Section 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. 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 shall offer 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 such 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. It shall be presumed that a Participant has refused his consent if the Managing General Partner has not received his consent within 30 days after the Managing General Partner mailed the request for 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 46 General Partner at the best price reasonably obtainable from an independent third party who is not an Affiliate of 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 wire addressed to the party to receive the notice at the address designated in Section 1.03. If there is a transfer of rights under this Agreement, no notice to the transferee shall be required, nor shall the transferee have any rights under this Agreement, until notice shall have been given to the Managing General Partner. Any transfer of rights under this Agreement shall not increase the duty to give notice. If there is a transfer of rights under this Agreement to more than one party, then notice to any owner of any interest in the rights shall be notice to all owners of the interest. 8.01(b). CHANGE IN ADDRESS. The address of any party to this Agreement may be changed by: (i) written notice 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 telegraph 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 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. The Managing General Partner shall send the first request and the time period shall be not less than 15 business days from the date of mailing of the request. If the Participant does not respond to the first request then the Managing General Partner shall send a second request. If the Participant does not respond within seven calendar days from the date of the mailing of 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 Commonwealth of Pennsylvania, provided, however, this Section 8.03 shall not be deemed to limit causes of action for violations of federal or state securities law to the laws of the Commonwealth of Pennsylvania. 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 upon all parties executing this or similar agreements from and after the date of execution by each party. 47 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 Agreed Subscriptions equal a majority of the Partnership Subscription; or (ii) proposed in writing by Participants whose Agreed Subscriptions equal 10% or more of the Partnership Subscription and approved by an affirmative vote of Participants whose Agreed Subscriptions equal a majority of the Partnership Subscription. 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: (i) to add or substitute in the case of an assigning party additional Participants; (ii) to enhance the tax benefits of the Partnership to the parties; and (iii) to satisfy any requirements, conditions, guidelines, options, or elections contained in any opinion, directive, order, ruling, or regulation of the Securities and Exchange Commission, the Internal Revenue Service, 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. 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 will be so affected. 8.06. ADDITIONAL PARTNERS. Each Participant hereby 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 upon 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 and seal as of the day and year hereinabove shown. ATLAS: ATLAS RESOURCES, INC. Managing General Partner By: --------------------------------- Attest: --------------------------------- (SEAL) Secretary 48 EXHIBIT (I-A) 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 AMERICA PUBLIC #9 LTD. The undersigned agrees: 1. to serve as the Managing General Partner of ATLAS AMERICA PUBLIC #9 LTD. (the "Partnership"), and hereby executes, swears to and agrees to all the terms of the Partnership Agreement; 2. to pay the required subscription of the Managing General Partner under Section 3.03(b)(1) of the Partnership Agreement; and 3. to subscribe to the Partnership as follows: (a) $___________________ [________] Unit(s)] under Section 3.03(b)(2) of the Partnership Agreement as a Limited Partner; or (b) $___________________ [________] Unit(s)] under Section 3.03(b)(2) of the Partnership Agreement as an Investor General Partner. MANAGING GENERAL PARTNER: Atlas Resources, Inc. Address: By:________________________________ 311 Rouser Road Moon Township, Pennsylvania 15108 ACCEPTED this ____ day of _________ , 2000. ATLAS RESOURCES, INC. MANAGING GENERAL PARTNER By:_______________________________ Attest _______________________________ (SEAL) Secretary EXHIBIT (I-B) SUBSCRIPTION AGREEMENT ATLAS AMERICA PUBLLC #9 LTD. _______________________________________________________________________________ SUBSCRIPTION AGREEMENT _______________________________________________________________________________ I, the undersigned, hereby offer to purchase Units of Atlas America Public #9 Ltd. in the amount set forth on the Signature Page of this Subscription Agreement and on the terms described in the current Prospectus for Atlas America Public #9 Ltd. (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 Amended and Restated Certificate and 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 Agreed Subscription is accepted by 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 Atlas Resources, Inc. (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 Amended and Restated Certificate and Agreement of Limited Partnership and any certificates related thereto. In order to induce the Managing General Partner to accept this subscription, I hereby represent, warrant, covenant and agree as follows: INVESTOR'S INITIALS _____ I have received the Prospectus. _____ I (other than if I am a Minnesota 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 the following: - 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 a partnership, corporation or trust, then the members, stockholders or beneficiaries thereof are citizens of the United States and each is at least twenty-one years of age. I am 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 the exhibits thereto. _____ (a) I have: - a net worth of at least $225,000 (exclusive of home, furnishings and automobiles); or - a net worth (exclusive of home, furnishings and automobiles) of: - at least $60,000; and 1 - had during the last tax year, or estimate that I will have during the current tax year, "taxable income" as defined in Section 63 of the Code of at least $60,000, without regard to an investment in the Partnership. (b) IN ADDITION, IF I AM A RESIDENT OF ALABAMA, ARIZONA, CALIFORNIA, INDIANA, IOWA, KANSAS, KENTUCKY, MAINE, MASSACHUSETTS, MICHIGAN, MINNESOTA, MISSISSIPPI, MISSOURI, NEW HAMPSHIRE, NEW MEXICO, NORTH CAROLINA, OHIO, OKLAHOMA, OREGON, PENNSYLVANIA, SOUTH DAKOTA, TENNESSEE, TEXAS, VERMONT OR WASHINGTON, THEN I REPRESENT THAT I AM AWARE OF AND MEET THAT STATE'S QUALIFICATIONS AND SUITABILITY STANDARDS SET FORTH IN EXHIBIT (B) TO THE PROSPECTUS. (c) 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) or (b) above. _____ I 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 Agreed Subscription to the extent the obligations and liabilities exceed the following: - the Partnership's insurance proceeds; - the Partnership's assets; and - indemnification by the Managing General Partner. Insurance may be inadequate to cover these liabilities and there is no insurance coverage for certain claims. _____ I 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 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 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 oil and gas; - the financial hazards involved in the offering, including the risk of losing the entire investment; - the lack of liquidity of this investment; - the restrictions on transferability of the Units; - the background of the Managing General Partner and the Operator; - the tax consequences of the investment; and - the unlimited joint and several liability of the Investor General Partners. 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 herein. In the case of sales to fiduciary accounts, the minimum standards set forth herein 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 interests if the donor or grantor is the fiduciary. 2 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 Agreed Subscription without liability to you. Agreed Subscriptions will be accepted or rejected by the Partnership within 30 days of their receipt. If your Agreed Subscription is rejected, then all of your funds will be returned to you immediately. If your Agreed 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 Agreed 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 Agreed Subscription was accepted by the Partnership. The Managing General Partner may not complete a sale of Units to you until at least five business days after the date you receive a final Prospectus. In addition, the Managing General Partner will send you a confirmation of purchase. 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 of the size of the area on the basis of geological data in all cases. If a resident of California I acknowledge the receipt of California Rule 260.141.11 set forth in Exhibit (B) to the Prospectus. 3 _______________________________________________________________________________ SIGNATURE PAGE OF SUBSCRIPTION AGREEMENT _______________________________________________________________________________ I, the undersigned, agree to purchase ________ Units of Participation at $10,000 per Unit in ATLAS AMERICA PUBLIC #9 LTD. (the "Partnership") as (check one): / / INVESTOR GENERAL PARTNER AGREED SUBSCRIPTION / / LIMITED PARTNER $ ___________________________ (______________________# Units) INSTRUCTIONS _______________________________________________________________________________ Make check payable to: "Atlas America Public #9 Ltd., Escrow Agent, National City Bank of PA" Minimum Subscription: one Unit ($10,000), however, the Managing General Partner, in its discretion, may accept one-half Unit ($5,000) subscriptions. 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. _______________________________________________________________________________ Subscriber (All individual investors must My Home Address (Do not use P.O. Box) personally sign this Signature Page.) _________________________________________________ ___________________________________________________ Print Name _________________________________________________ ___________________________________________________ Signature _________________________________________________ ___________________________________________________ Print Name _________________________________________________ Signature _________________________________________________ Name of Entity if a Trust, Corporation or Partnership is Subscribing Date: _______________ My Address for Distributions if Different from Above ___________________________________________________ ___________________________________________________ My Telephone No.: Business _________________________ Home __________________ Email Address__________ My Tax I.D. No. (Social Security No.): _____________________________________________________________ (CHECK ONE): I am a: Calendar Year Taxpayer / / Fiscal Year Taxpayer / / (CHECK ONE): OWNERSHIP OF THE UNITS- Tenants-in-Common / / Partnership / / Joint Tenancy / / C Corporation / / Individual / / S Corporation / / Trust / / Community Property / / Other / /
1 ________________________________________________________________________________ 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 NASD's 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 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. _________________________________________ _______________________________________________ Registered Representative Name and Number Name of Broker-Dealer Registered Representative Office Address: _______________________________________________ CRD Number _____________________________________________ _______________________________________________ Company Name (if other than Broker-Dealer Name) _____________________________________________ _____________________________________________ Phone Number; Facsimile Number, Email Address NOTICE TO BROKER-DEALER: Send complete and signed DOCUMENTS and THE CHECK to: Mr. John S. Coffey Anthem Securities, Inc. P.O. Box 926 Coraopolis, Pennsylvania 15108-0911 (412) 262-1680 FACSIMILE: (412) 262-7430 EMAIL: jcoffey@atasamerica.com ________________________________________________________________________________ TO BE COMPLETED BY THE MANAGING GENERAL PARTNER ________________________________________________________________________________ ACCEPTED THIS ______ day ATLAS RESOURCES, INC., of _________________ , 2000 MANAGING GENERAL PARTNER Attest By:_______________________________________ _________________________________________ (SEAL) Secretary
2 EXHIBIT (II) DRILLING AND OPERATING AGREEMENT ATLAS AMERICA PUBLIC #9 LTD. (THIS DRILLING AND OPERATING AGREEMENT WILL BE APPROPRIATELY MODIFIED FOR OTHER AREAS OF THE UNITED STATES. THE AMOUNT OF THE WELL SUPERVISION FEES WILL BE AS DESCRIBED IN "COMPENSATION" IN THE PROSPECTUS.) INDEX
SECTION PAGE 1. Assignment of Well Locations; Representations; Designation of Additional Well Locations; Outside Activities........................................................................................1 2. Drilling of Wells; Timing; Depth; Interest of Developer; Right of Substitution.............................2 3. Operator - Responsibilities in General; Covenants; Term.....................................................3 4. Operator's Charges for Drilling and Completing Wells; Payment; Completion Determination; Excess Funds if Dry Hole..................................................................................4 5. Title Examination of Well Locations; Liability for Title Defects............................................5 6. Operations Subsequent to Completion of the Wells; Fee Adjustments; Extraordinary Costs; Pipelines; Price Determinations; Plugging and Abandonment.................................................6 7. Billing and Payment Procedure with Respect to Operation of Wells; Disbursements; Records and Reports; Additional Information.......................................................................7 8. Operator's Lien; Right to Collect From Gas Purchaser........................................................9 9. Successors and Assigns; Transfers; Appointment of Agent.....................................................9 10. Operator's Insurance; Subcontractors' Insurance; Operator's Liability......................................10 11. Internal Revenue Code Election, Relationship of Parties; Right to Take Production in Kind..................11 12. Force Majeure..............................................................................................11 13. Term.......................................................................................................12 14. Governing Law and Invalidity...............................................................................12 15. Integration................................................................................................12 16. Waiver of Default or Breach................................................................................12 17. Notices....................................................................................................12 18. Interpretation.............................................................................................13 19. Counterparts...............................................................................................13 Signature Page.............................................................................................13 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 _______________, 2000, by and between ATLAS RESOURCES, INC., a Pennsylvania corporation (hereinafter referred to as "Atlas" or "Operator"), and ATLAS AMERICA PUBLIC #9 LTD., a Pennsylvania 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 hereto and made a part hereof, has certain rights to develop the ____________ (______) initial well locations identified on the maps attached hereto as Exhibits A-l through A-______ (the "Initial Well Locations"); WHEREAS, the Developer, subject to the terms and conditions hereof, desires to acquire certain of the Operator's rights to develop the aforesaid ____________ (______) Initial Well Locations and to provide for the development upon the terms and conditions herein set forth of additional well locations ("Additional Well Locations") which 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 (hereinafter collectively referred to as the "Well Locations") and to operate the wells completed thereon, on the terms and conditions herein set forth; 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; DESIGNATION OF ADDITIONAL WELL LOCATIONS; OUTSIDE ACTIVITIES. (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 top of the Queenston formation in Pennsylvania and Ohio. The assignment shall be substantially in the form of Exhibit B attached hereto and made a part hereof. The amount of acreage included in each Initial Well Location and the configuration thereof are indicated on the maps attached hereto as Exhibits A-l through A-______. The amount of acreage included in each Additional Well Location and the configuration thereof shall be indicated on the maps to be attached as exhibits to the applicable addendum as provided in sub-section (c) below. (b) REPRESENTATIONS. As of the date hereof, the Operator represents and warrants to the Developer that: (i) the Operator is the lawful owner of said Lease and rights and interest thereunder and of the personal property thereon or used in connection therewith; (ii) the Operator has good right and authority to sell and convey the same; (iii) said rights, interest and property are free and clear from all liens and encumbrances; and (iv) all rentals and royalties due and payable thereunder have been duly paid. The foregoing representations and warranties shall also be made by the Operator at the time of each recorded assignment of the acreage included in each Initial Well Location and at the time of each recorded assignment of the acreage included in each Additional Well Location designated pursuant to sub-section (c) below, such representations and warranties to be included in each recorded assignment substantially in the manner set forth in the form of assignment attached hereto and made a part hereof as Exhibit B. 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 aforesaid representations and warranties. It is understood and agreed 1 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. In the event that the parties hereto desire to designate Additional Well Locations to be developed in accordance with the terms and conditions of this Agreement, each of said parties shall execute an addendum substantially in the form of Exhibit C attached hereto and made a part hereof specifying: (i) the undivided percentage of Working Interest and the Oil and Gas Leases to be included as Leases hereunder; (ii) the amount and configuration of acreage included in each such Additional Well Location on maps attached as exhibits to such addendum; and (iii) their agreement that such Additional Well Locations shall be developed in accordance with the terms and conditions of this Agreement. (d) OUTSIDE ACTIVITIES. 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 described herein and to the Additional Well Locations designated pursuant to sub-section (c) above. Nothing contained in this Agreement shall be interpreted to restrict in any manner the right of each of the parties hereto to conduct without the participation of any other party hereto 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 aforesaid Initial and Additional Well Locations or elsewhere. 2. DRILLING OF WELLS; TIMING; DEPTH; INTEREST OF DEVELOPER; RIGHT OF SUBSTITUTION. (a) DRILLING OF WELLS. Operator, as Developer's independent contractor, agrees to drill, complete (or plug) and operate ____________ (_____) natural 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 the wells and any extra costs pursuant to Section 4 hereof in proportion to the share of the Working Interest owned by the Developer in the wells with respect to all ___________ (______) initial wells, it being expressly 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 hereunder. (b) TIMING. Operator will use its best efforts to commence drilling the first well within thirty (30) days after the date of this Agreement and to commence the drilling of each of said ______________ (_____) initial wells for which payment is made pursuant to Section 4(b) of this Agreement, on or before March 31, 2001. Subject to the foregoing time limits, Operator shall determine the timing of and the order of the drilling of said ____________ (______) Initial Well Locations. (c) DEPTH. The ____________ (______) initial wells to be drilled on the Initial Well Locations designated pursuant to this Agreement and any additional wells drilled hereunder on any Additional Well Locations designated pursuant to Section l(c) above shall be 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 shall be drilled to a depth sufficient to test thoroughly the objective formation or the deepest assigned depth, whichever is less. (d) INTEREST OF DEVELOPER. Except as otherwise provided herein, 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 the Prospect, equipment, materials, and facilities acquired, constructed or installed hereunder 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 hereunder shall be owned by the Developer in proportion to the share of the Working Interest owned by the Developer in the wells. (e) RIGHT OF SUBSTITUTION. 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 commence hereunder with respect to such Well Location, based upon: (i) the production (or failure of production) of any other wells which may have been recently drilled in the immediate area of such Well Location; (ii) upon newly discovered title defects; or 2 (iii) upon such other evidence with respect to the Well Location as may be obtained, that it would not be in the best interest of the parties hereto to drill a well on such Well Location, then the party making the determination shall notify the other party hereto of such determination and the basis therefore and, unless otherwise instructed by Developer, such well shall not be drilled. If such well is not drilled, Operator shall promptly propose a new well location (including such information with respect thereto as Developer may reasonably request) within Pennsylvania, Ohio, or other areas of the United States to be substituted for such original Well Location. Developer shall thereafter have the option for a period of 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 hereof. Once the Developer accepts a substitute well location or does not reject it within said 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 hereof. 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 hereunder do the following: (i) make the necessary arrangements for the drilling and completion of wells and the installation of the necessary gas gathering line systems and connection facilities; (ii) make the technical decisions required in drilling, testing, completing and operating such wells; (iii) manage and conduct all field operations in connection with the drilling, testing, completing, equipping, operating and producing of the wells; (iv) maintain all wells, equipment, gathering lines and facilities in good working order during the useful life thereof; and (v) perform the necessary administrative and accounting functions. In the performance of 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: (i) it shall perform and carry on (or cause to be performed and carried on) its duties and obligations hereunder 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 aforesaid Well Locations; (ii) all drilling and other operations conducted by, for and under the control of Operator hereunder 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 hereunder pursuant to a written estimate shall conform to the technical specifications set forth in such written estimate and all equipment and materials installed or incorporated in the wells and facilities hereunder shall be new or used and of good quality; (iv) in the course of conducting operations hereunder, it shall comply with all terms and conditions of the Leases (and any related assignments, amendments, subleases, modifications and supplements) other than any minimum drilling commitments contained therein; (v) it shall keep the Well Locations subject to this Agreement and all wells, equipment and facilities located thereon, free and clear of all labor, materials and other liens or encumbrances arising out of operations hereunder; 3 (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 which are the subject of this Agreement; and (vii) it will provide competent and experienced personnel to supervise the drilling, completing (or plugging), and operating of 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 hereunder. (c) TERM. Atlas shall serve as Operator hereunder until the earliest of: (i) the termination of this Agreement pursuant to Section 13 hereof; (ii) the termination of Atlas as Operator by the Developer which may be effected by the Developer at any time in its discretion, with or without cause; upon sixty (60) days advance written notice to the Operator; or (iii) the resignation of Atlas as Operator hereunder which may occur upon ninety (90) days' written notice to the Developer at any time after five (5) years from the date hereof, it being expressly understood and agreed that Atlas shall have no right to resign as Operator hereunder prior to the expiration of the aforesaid five-year period. Any successor Operator hereunder shall be selected by the Developer. Nothing contained in this sub-section (c) shall relieve or release Atlas or the Developer from any liability or obligation hereunder which accrued or occurred prior to Atlas' removal or resignation as Operator hereunder. Upon any change in Operator pursuant to 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 hereunder and owned by the Developer. 4. OPERATOR'S CHARGES FOR DRILLING AND COMPLETING WELLS; PAYMENT; COMPLETION DETERMINATION; EXCESS FUNDS IF DRY HOLE. (a) OPERATOR'S CHARGES FOR DRILLING AND COMPLETING WELLS. All natural gas wells which are drilled and completed hereunder shall be drilled and completed on a Cost plus 15% basis. "Cost," when used with respect to services, shall mean the reasonable, necessary and actual expenses incurred by Operator on behalf of Developer in providing the services under this Agreement, determined in accordance with generally accepted accounting principles. As used elsewhere, "Cost" shall mean the price paid by Operator in an arm's-length transaction. The estimated price for each of said natural gas wells shall be set forth in an AFE which shall be attached to this Agreement as an Exhibit, and shall cover all ordinary costs which may be incurred in drilling and completing each such well for production of natural gas, including without limitation, site preparation, permits and bonds, roadways, surface damages, power at the site, water, Operator's overhead and profit, rights-of-way, drilling rigs, equipment and materials, costs of title examination, 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, geological and engineering services and completing two (2) zones. Such estimated price shall not include the cost of: (i) completing more than two (2) zones; (ii) completion procedures, equipment, or any facilities necessary or appropriate for the production and sale of oil and/or natural gas liquids; and (iii) equipment or materials necessary or appropriate to collect, lift or dispose of liquids for efficient gas production, except that the cost of saltwater collection tanks, separators, siphon string and tubing shall be included in the aforesaid estimated price. Any such extra costs shall be billed to Developer in proportion to the share of the Working Interest owned by the Developer in the wells on a Cost plus 15% basis. (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 Intangible Drilling Costs as hereinafter defined for drilling and completing all initial wells upon execution of this Agreement, which payment shall be nonrefundable in all events, in order to enable Operator to do the following: (i) commence site preparation for ________________ (______) initial wells; 4 (ii) obtain suitable subcontractors for the drilling and completion of such wells at currently prevailing prices; and (iii) insure the availability of equipment and materials. Atlas' payments for the Tangible Costs as hereinafter defined 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 such costs have been incurred. For purposes of this Agreement, "Intangible Drilling Costs" 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 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," including the expense of plugging and abandoning any well before a completion attempt. "Tangible Costs" shall mean those costs associated with the drilling and completion of oil and gas wells which are generally accepted as capital expenditures pursuant to the provisions of the Code. This includes all costs of equipment, parts and items of hardware used in drilling and completing a well, and those items necessary to deliver acceptable oil and gas production to purchasers to the extent installed downstream from the wellhead of any well and which are required to be capitalized pursuant to applicable provisions of the Code and regulations promulgated thereunder. With respect to each additional well drilled on the Additional Well Locations, if any, Developer shall pay Operator, in proportion to the share of the Working Interest owned by the Developer in the wells, one hundred percent (100%) of the estimated Intangible Drilling Costs for such well upon execution of the applicable addendum pursuant to Section l(c) above, which payment shall be nonrefundable in all events, in order to enable Operator to do the following: (i) commence site preparation; (ii) obtain suitable subcontractors for the drilling and completion of such wells at currently prevailing prices; and (iii) insure the availability of equipment and materials. Atlas' payments for the 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 such costs have been incurred. Developer shall pay, in proportion to the share of the Working Interest owned by the Developer in the wells, any extra costs incurred with respect to each well pursuant to sub-section (a) above within ten (10) business days of its receipt of Operator's statement therefore. (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 hereunder; provided, however, that 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) EXCESS FUNDS IF DRY HOLE. If Operator determines at any time during the drilling or attempted completion of any well hereunder, 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 such well should not be completed, it shall promptly and properly plug and abandon the same. Any Intangible Drilling Costs paid by Developer with respect to such dry hole which exceed Operator's price specified in sub-section (a) above for such dry hole shall be retained by Operator and shall be applied to the Intangible Drilling Costs for an additional well or wells to be drilled on the Additional Well Locations or to cost overruns over the estimated price for Intangible Drilling Costs, if any, on one or more of the other initial or additional wells, to be drilled by Operator on Developer's behalf. 5. TITLE EXAMINATION OF WELL LOCATIONS; LIABILITY FOR TITLE DEFECTS. (a) TITLE EXAMINATION OF WELL LOCATIONS. The Developer hereby acknowledges that Operator has furnished Developer with the title opinions identified on Exhibit A, and other documents and information which 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 5 Developer hereby accepts the title to said 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) hereof, any loss, expense, cost or liability whatsoever caused by or related to any defect or failure of such title shall be the sole responsibility of and shall be borne entirely by the Developer. (b) LIABILITY FOR TITLE DEFECTS. Prior to commencing the drilling of any well on any Additional Well Location designated pursuant to this Agreement, Operator shall conduct, or cause to be conducted, a title examination of such 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 such Lease. The results of such 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, and no drilling shall be commenced until such title has been accepted in writing by the Developer. After any title has been accepted by the Developer, any loss, expense, cost or liability whatsoever, caused by or related to any defect or failure of such 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) of this Agreement. 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. Commencing with the month in which a well drilled hereunder begins to produce, Operator shall be entitled to an operating fee of $275 per month for each well being operated under this Agreement, proportionately reduced to the extent the Developer owns less than 100% of the Working Interest in the wells. 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 such wells and related pipelines and facilities. Such 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 paid by the Developer in proportion to the share of the Working Interest owned by the Developer in the wells. Any well which is temporarily abandoned or shut-in continuously for the entire month shall not be considered a producing well for purposes of determining the number of wells in such month subject to the aforesaid operating fee. (b) FEE ADJUSTMENTS. The monthly operating fee set forth in sub-section (a) above may in the following manner be adjusted annually as of the first day of January (the "Adjustment Date") each year beginning January l, 2002. Such 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, 2000, in the case of the first adjustment, and since the previous Adjustment Date, in the case of each subsequent adjustment. 6 (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 hereunder reasonably estimated to result in an expenditure of more than $5,000, unless such 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, contractors, licensees or invitees. All extraordinary costs incurred and the cost of projects undertaken with respect to a well being produced hereunder shall be billed at the invoice cost of third party services performed or materials purchased together with a reasonable charge by Operator for 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 of undertaking any such project all or a portion of the estimated costs thereof in proportion to the share of the Working Interest owned by the Developer in the wells. (d) PIPELINES. Developer shall have no interest in the pipeline gathering system, which gathering system shall remain the sole property of Operator and shall be maintained at Operator's sole cost and expense. (e) PRICE DETERMINATIONS. Notwithstanding anything herein to the contrary, the Developer shall have full responsibility for and bear 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. Such 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 said Act and the implementing state regulations. Operator agrees to furnish such information and render such assistance as the Developer may reasonably request in order to comply with said 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 which has been completed hereunder as a producer. In addition, Operator shall not plug and abandon any such well prior to obtaining the written consent of the Developer. However, if the Operator 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, determines that any such well should be plugged and abandoned and makes a written request to the Developer for authority to plug and abandon any such well and the Developer fails to respond in writing to such request within forty-five (45) days following the date of such request, then the Developer shall be deemed to have consented to the plugging and abandonment of such well(s). All costs and expenses related to plugging and abandoning the wells which have been drilled and completed as producing wells hereunder shall be borne and paid by the Developer in proportion to the share of the Working Interest owned by the Developer in the wells. At any time after three (3) years from the date each well drilled and completed hereunder 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 operated hereunder up to $200, in proportion to the share of the Working Interest owned by the Developer in the wells, for the purpose of establishing a fund to cover the estimated costs of plugging and abandoning said well. All such funds shall be deposited 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 such costs. 7. BILLING AND PAYMENT PROCEDURE WITH RESPECT TO OPERATION OF WELLS; DISBURSEMENTS; 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, all severance taxes, royalties, overriding royalties, operating fees, pipeline gathering charges and other expenses and liabilities payable and incurred by reason of its operation of the wells in accordance with this Agreement. Operator shall also pay, in proportion to the share of the Working Interest owned by the Developer in the wells, on or before the due date any third party invoices rendered to Operator with respect to such costs and expenses. Operator, however, shall not be required to pay and discharge as aforesaid any such costs and expenses which are being contested in good faith by Operator. 7 Operator shall deduct the foregoing costs and expenses from the Developer's share of the proceeds of the oil and/or gas sold from the wells operated hereunder and shall keep an accurate record of the Developer's account hereunder, showing expenses incurred and charges and credits made and received with respect to each well. In the event that such proceeds are insufficient to pay said costs and expenses, Operator shall promptly and timely pay and discharge the same, 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 said costs and expenses. The invoice shall be accompanied by the form of statement specified in sub-section (b) below. Any such invoice 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 hereunder, less: (i) the amounts charged to the Developer under sub-section (a) hereof; and (ii) such amount, if any, withheld by Operator for future plugging costs pursuant to sub-section (f) of Section 6. Each such disbursement made and/or invoice submitted pursuant to sub-section (a) above shall be accompanied by a statement 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 thereof; (ii) the total proceeds received from any sale thereof, and the Developer's share thereof; (iii) the costs and expenses deducted from said proceeds and/or being billed to the Developer pursuant to sub-section (a) above; (iv) the amount withheld for future plugging costs; and (v) such other information as Developer may reasonably request, including without limitation copies of all third party invoices listed thereon for such period. Operator agrees to deposit all proceeds from the sale of oil and/or gas sold from the wells operated hereunder 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 hereunder. (c) 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 hereunder, shall furnish the Developer with a detailed statement itemizing with respect to such well the total costs and charges under Section 4(a) hereof and the Developer's share thereof, and such information as is necessary to enable the Developer: (i) to allocate any extra costs incurred with respect to such well between tangible and intangible; and (ii) to determine the amount of investment tax credit, if applicable. (d) ADDITIONAL INFORMATION. Upon request, Operator shall promptly furnish the Developer with such additional information as it may reasonably request, including without limitation geological, technical and financial information, in such 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) upon at least ten (10) days' written notice have access during normal business hours to all of Operator's records pertaining to operations hereunder, including without limitation, the right to audit the books of account of Operator relating to all receipts, costs, charges and expenses under this Agreement; and (ii) have access, at its sole risk, to any wells drilled by Operator hereunder at all times to inspect and observe any machinery, equipment and operations. 8 8. OPERATOR'S LIEN; RIGHT TO COLLECT FROM GAS PURCHASER. (a) OPERATOR'S LIEN. The Developer hereby grants Operator a first and preferred lien on and security interest in the interest of the Developer covered by this Agreement, and in the Developer's interest in oil and gas produced and the proceeds thereof, and upon the Developer's interest in materials and equipment, to secure the payment of all sums due from Developer to Operator under the provisions of this Agreement. (b) RIGHT TO COLLECT FROM GAS PURCHASER. In the event that the Developer fails to pay any amount owing hereunder by it to the Operator within the time limit for payment thereof, Operator, without prejudice to other existing remedies, is authorized at its election to collect from any purchaser or purchasers of oil or gas and retain the proceeds from the sale of the Developer's share thereof 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 such delinquency, has been paid. Each purchaser of oil or gas shall be entitled to rely upon 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 upon and shall inure to the benefit of the undersigned parties and their respective successors and permitted assigns; provided, however, that Operator may not assign, transfer, pledge, mortgage, hypothecate, sell or otherwise dispose of any of its interest in this Agreement, or any of the rights or obligations hereunder, without the prior written consent of the Developer, except that such consent shall not be required in connection with: (i) the assignment of work to be performed for Operator by subcontractors, it being understood and agreed, however, that any such 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 or pursuant to Operator's present or future financing arrangements, or (iii) the liquidation, merger, consolidation or sale of substantially all of the assets of Operator or other corporate reorganization. Further, in order to maintain uniformity of ownership in the wells, production, equipment, and leasehold interests covered by this Agreement, and notwithstanding any other provisions 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 hereby unless such disposition encompasses either: (i) the entire interest of the Developer in all wells, production, equipment and leasehold interests subject hereto; 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 hereby shall be made: (i) expressly subject to this Agreement; (ii) without prejudice to the rights of the other party; and (iii) in accordance with and subject to the provisions of the Lease. (c) APPOINTMENT OF AGENT. If at any time the interest of the Developer is divided among or owned by co-owners, Operator may, at its discretion, require such 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; 9 (iii) receive billings for and approve and pay all costs, expenses and liabilities incurred hereunder; (iv) exercise any rights granted to such 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 hereby; and (vii) deal generally with, and with power to bind, such co-owners with respect to all activities and operations contemplated by this Agreement. However, all such 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 hereunder in accordance with sub-section (c) of Section 11 hereof. 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 hereunder 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 insurance shall include coverage for blow-outs and total liability coverage of not less than $10,000,000. Subject to the aforesaid 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 thereof shall be delivered to the Developer upon request. It is understood and agreed that Operator's insurance coverage may not adequately protect the interests of the Developer hereunder and that the Developer shall carry at its expense such 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 hereunder 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) relating to, caused by or arising out of: (i) the noncompliance with or violation by Operator, its employees, agents, or subcontractors of any local, state or federal law, statute, regulation, or ordinance; (ii) the negligence or misconduct of Operator, its employees, agents or subcontractors; or (iii) the breach of or failure to comply with any provisions of this Agreement. 10 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 hereto elects, under the authority of Section 761(a) of the Internal Revenue Code of 1986, as amended, to be excluded from the application of all of the provisions of Subchapter K of Chapter 1 of Sub Title 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 hereby is located contain, or may hereafter contain, provisions similar to those contained in the Subchapter of the Internal Revenue Code of 1986, as amended, referred to under which a similar election is permitted, each of the parties agrees that such election shall be exercised. Beginning with the first taxable year of operations hereunder, 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) and (ii) of said Regulations to revoke such election. Each party hereby agrees to execute such documents and make such filings with the appropriate governmental authorities as may be necessary to effect such election. (b) RELATIONSHIP OF PARTIES. It is not the intention of the parties hereto 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 herein or as otherwise directed by the Developer. (c) RIGHT TO TAKE PRODUCTION IN KIND. Subject to the provisions of Section 8 hereof, 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 hereunder, exclusive of: (i) production which may be used in development and producing operations; (ii) production unavoidably lost; and (iii) production 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 such 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 hereunder. 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 hereunder. The Developer agrees to designate Operator or Operator's designated bank agent as the Developer's collection agent in any such contract. Upon request, Operator shall render assistance in arranging such sale or disposition and shall promptly provide the Developer with all relevant information which comes to Operator's attention regarding opportunities for sale of production. In the event Developer shall fail to make the arrangements necessary to take in kind or separately dispose of its proportionate share of the oil and gas produced hereunder, Operator shall have the right, subject to the revocation at will by the Developer, but not the obligation, to purchase such 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 such production, however, Operator shall have no liability to Developer should Operator fail to market such 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 any other party's share of oil and gas shall be only for such reasonable periods of time as are consistent with the minimum needs of the Industry under the particular circumstance, but in no event for a period in excess of one (1) year. 12. FORCE MAJEURE. If Operator is rendered unable, wholly or in part, by force majeure (as hereinafter defined) to carry out its obligations under this Agreement, the Operator shall give to the Developer prompt written notice of the force majeure with reasonably full particulars concerning it; thereupon, 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. Operator shall use all reasonable diligence to remove the force majeure as quickly as possible to the extent the same is within reasonable control. The term "force majeure" shall mean an act of God, strike, lockout, or other industrial disturbance, act of the public enemy, war, blockade, public riot, lightning, fire, storm, flood, explosion, governmental restraint, unavailability of equipment or materials, 11 plant shut-downs, curtailments by purchasers and any other causes whether of the kind specifically enumerated above or otherwise, which directly precludes Operator's performance hereunder and is not reasonably within the control of the Operator. 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 all such 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, the Agreement shall continue and remain in full force and effect for the productive lives of the wells being operated hereunder. 14. GOVERNING LAW AND INVALIDITY. This Agreement shall be governed by, construed and interpreted in accordance with the laws of the Commonwealth of Pennsylvania. The invalidity or unenforceability of any particular provision of this Agreement shall not affect the other provisions hereof, and this Agreement shall be construed in all respects as if such invalid or unenforceable provision were omitted. 15. INTEGRATION. This Agreement, including the Exhibits hereto, constitutes and represents the entire understanding and agreement of the parties with respect to the subject matter hereof and supersedes all prior negotiations, understandings, agreements, and representations relating to the subject matter hereof. 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 such change, waiver, modification, or amendment is sought to be enforced. 16. WAIVER OF DEFAULT OR BREACH. No waiver by any party hereto 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 herein, all notices, statements, requests, or demands which 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 changed by certified or registered letter so addressed to the other party: (i) If to the Operator, to: Atlas Resources, Inc. 311 Rouser Road Moon Township, Pennsylvania 15108 Attention: President (ii) If to Developer, to: Atlas America Public #9 Ltd. c/o Atlas Resources, Inc. 311 Rouser Road Moon Township, Pennsylvania 15108 Notices which are served by registered or certified mail upon the parties hereto in the manner provided in this Section shall be deemed sufficiently served or given for all purposes under this Agreement at the time such notice shall be mailed as provided herein in any post office or branch post office regularly maintained by the United States Postal Service or any successor to the functions thereof. All payments hereunder shall be hand-delivered or sent by United States mail, postage prepaid to the addresses set forth above until changed by certified or registered letter so addressed to the other party. 12 18. INTERPRETATION. Whenever this Agreement makes reference to "this Agreement" or to any provision "hereof," or words to similar effect, the reference shall be construed to refer to the within instrument unless the context clearly requires otherwise. The titles of the Sections herein have been inserted as a matter of convenience of reference only and shall not control or affect the meaning or construction of any of the terms and provisions hereof. As used in this Agreement, the plural shall include the singular and the singular shall include the plural whenever appropriate. 19. COUNTERPARTS. The parties hereto may execute this Agreement in any number of separate counterparts, each of which, when executed and delivered by the parties hereto, shall have the force and effect of an original; but all such counterparts shall be deemed to constitute one and the same instrument. IN WITNESS WHEREOF, the parties hereto have duly executed this Agreement under their respective seals as of the day and year first above written. Attest ATLAS RESOURCES, INC. By: --------------------------------------- ------------------------------------ Secretary [Corporate Seal] ATLAS AMERICA PUBLIC #9 LTD. Attest By its Managing General Partner: ATLAS RESOURCES, INC. --------------------------------------- Secretary [Corporate Seal] By: ------------------------------------ 13 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 bottom of the __________________ Formation, subject to the landowner's royalty interest and Overriding Royalty Interests. Exhibit A (Page 1) WELL NAME, TWP. COUNTY, STATE ASSIGNMENT OF OIL AND GAS LEASE STATE OF ____________ COUNTY OF ___________ KNOW ALL MEN BY THESE PRESENTS: THAT the undersigned ___________________________________________________ (hereafter 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 _______________________________________________________________________________ (hereafter 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 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 ________________, 19___. Signed and acknowledged in presence of ____________________________________ ______________________________________ ____________________________________ ______________________________________ ____________________________________ Exhibit B ACKNOWLEDGEMENT 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., 19 ___. ______________________________ Notary Public CORPORATION ACKNOWLEDGEMENT 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 herewith set my hand and official seal at ____________, this _____ day of _____________, A.D., 19 _____. ______________________________ Notary Public This instrument prepared by: Atlas Resources, Inc. 311 Rouser Road P.O. Box 611 Moon Township, PA 15108 Exhibit B ADDENDUM NO. __________ TO DRILLING AND OPERATING AGREEMENT DATED ___________________ , 2000 THIS ADDENDUM NO. __________ made and entered into this ______ day of ________________, 2000, by and between ATLAS RESOURCES, INC., a Pennsylvania corporation (hereinafter referred to as "Operator"), and ATLAS AMERICA PUBLIC #9 LTD., a Pennsylvania limited partnership, (hereinafter referred to as the Developer). WITNESSETH THAT: WHEREAS, Operator and the Developer have entered into a Drilling and Operating Agreement dated ___________________, 2000, (the "Agreement"), which Agreement relates to the drilling and operating of ________________ (______) natural gas wells on the ________________ (______) Initial Well Locations in _________________, ___________, identified on the maps attached as Exhibits A-l through A-______ to said Agreement, and provides for the development upon the terms and conditions therein set forth of such Additional Well Locations as the parties may from time to time designate; and WHEREAS, pursuant to Section l(c) of said Agreement, Operator and Developer presently desire to designate ________________ Additional Well Locations hereinafter described to be developed in accordance with the terms and conditions of said Agreement. NOW, THEREFORE, in consideration of the mutual covenants herein contained and intending to be legally bound hereby, the parties hereto agree as follows: 1. Pursuant to Section l(c) of the aforesaid Agreement, the Developer hereby authorizes Operator to drill, complete (or plug) and operate, upon the terms and conditions set forth in said Agreement and this Addendum No.__________, ________________ additional natural gas wells on the ________________ Additional Well Locations described on Exhibit A hereto and on the maps attached hereto as Exhibits A-______ through A-______. 2. Operator, as Developer's independent contractor, agrees to drill, complete (or plug) and operate said additional natural gas wells on said Additional Well Locations in accordance with the terms and conditions of said Agreement and further agrees to use its best efforts to commence drilling the first such additional well within thirty (30) days after the date hereof and to commence drilling all said ________________ additional wells on or before March 31, 2001. 3. Developer hereby acknowledges that Operator has furnished Developer with the title opinions identified on Exhibit A hereto, and such other documents and information which Developer or its counsel has requested in order to determine the adequacy of the title to the aforesaid Additional Well Locations. The Developer hereby accepts the title to the aforesaid Additional Well Locations and leased premises in accordance with the provisions of Section 5 of the Agreement. 4. The drilling and operation of said ________________ additional natural gas wells on the aforesaid ________________ Additional Well Locations shall be in accordance with and subject to the terms and conditions set forth in the aforesaid Agreement as supplemented by this Addendum No. __________ and except as previously supplemented, all terms and conditions of the aforesaid Agreement shall remain in full force and effect as originally written. 5. This Addendum No. __________ shall be legally binding upon, and shall inure to the benefit of, the parties hereto and their respective heirs, personal representatives, successors and assigns. Exhibit C (Page 1) WITNESS the due execution hereof on the day and year first above written. Attest: ATLAS RESOURCES, INC. By --------------------------------------- ------------------------------------ Secretary [Corporate Seal] ATLAS AMERICA PUBLIC #9 LTD. By its Managing General Partner: ATLAS RESOURCES, INC. Attest: By --------------------------------------- ------------------------------------ Secretary [Corporate Seal] Exhibit C (Page 2) EXHIBIT (B) SPECIAL SUITABILITY REQUIREMENTS AND DISCLOSURES TO INVESTORS SPECIAL SUITABILITY REQUIREMENTS AND DISCLOSURES TO INVESTORS If you are a resident of one of the following states, then you must meet that state's qualification and suitability standards as follows: SUBSCRIBERS TO LIMITED PARTNER UNITS. If you are a resident of: - Michigan; or - North Carolina; and you purchase limited partner units, then you must: - have a net worth of not less than $225,000, exclusive of home, furnishings and automobiles; or - have a net worth of not less than $60,000, exclusive of home, furnishings and automobiles, and estimated current year taxable income as defined in Section 63 of the Internal Revenue Code of 1986 of $60,000 or more without regard to an investment in the partnership. In addition, if you are a resident of: - Michigan; - Ohio; or - Pennsylvania; then you must not make an investment in the partnership in excess of 10% of your net worth, exclusive of home, furnishings and automobiles. If you are a resident of California and you purchase limited partners units, then you must: - have a net worth of not less than $250,000, exclusive of home, furnishings and automobiles, and expect to have gross income in the current year of $65,000 or more; or - have a net worth of not less than $500,000, exclusive of home, furnishings and automobiles; or - have a net worth of not less than $1,000,000; or - expect to have gross income in the current tax year of not less than $200,000. SUBSCRIBERS TO INVESTOR GENERAL PARTNER UNITS. If you are a resident of California and you purchase investor general partner units, then you must: - have a net worth of not less than $250,000, exclusive of home, furnishings and automobiles, and expect to have annual gross income in the current year of $120,000 or more; or - have a net worth of not less than $500,000, exclusive of home, furnishings and automobiles; or - have a net worth of not less than $1,000,000; or - expect to have gross income in the current year of not less than $200,000. 1 If you are a resident of: - Alabama; - Maine; - Massachusetts; - Minnesota; - North Carolina; - Ohio; - Pennsylvania; - Tennessee; or - Texas; and you purchase investor general partner units, then you must: - have an individual or joint net worth with your spouse of $225,000 or more, without regard to the investment in the partnership, exclusive of home, home furnishings and automobiles, and a combined gross income of $100,000 or more for the current year and for the two previous years; or - have an individual or joint net worth with your spouse in excess of $1,000,000, inclusive of home, home furnishings and automobiles; or - have an individual or joint net worth with your spouse in excess of $500,000, exclusive of home, home furnishings and automobiles; or - have 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. If you are a resident of: - Arizona; - Indiana; - Iowa; - Kansas; - Kentucky; - Michigan; - Mississippi; - Missouri; - New Hampshire; - New Mexico; 2 - Oklahoma; - Oregon; - South Dakota; - Vermont; or - Washington; and you purchase investor general partner units, then you must: - have an individual or joint net worth with your spouse of $225,000 or more, without regard to the investment in the partnership, exclusive of home, home furnishings and automobiles, and a combined "taxable income" of $60,000 or more for the previous year and expect to have a combined "taxable income" of $60,000 or more for the current year and for the succeeding year; or - have an individual or joint net worth with your spouse in excess of $1,000,000, inclusive of home, home furnishings and automobiles; or - have an individual or joint net worth with your spouse in excess of $500,000, exclusive of home, home furnishings and automobiles; or - have 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. In addition, if you are a resident of: - Michigan; - Ohio; or - Pennsylvania; then you must not make an investment in the partnership in excess of 10% of your net worth, exclusive of home, furnishings and automobiles. If a resident of Missouri, I am aware that: THESE SECURITIES ARE NOT ELIGIBLE FOR ANY TRANSACTIONAL EXEMPTION UNDER THE MISSOURI UNIFORM SECURITIES ACT (SECTION 409.402(b), R.S.MO.(1978). UNLESS THESE SECURITIES ARE AGAIN REGISTERED UNDER THE ACT, THEY MAY NOT BE REOFFERED FOR SALE OR RESOLD IN THE STATE OF MISSOURI (SECTION 409.301, R.S.MO.(1978)). 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. 3 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 Sections 260.102.6, 260.141.10 and 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'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 or 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 Sections 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 4 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." If a resident of 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. PENNSYLVANIA INVESTORS: Because the minimum closing amount is less than $1,500,000 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. 5 TABLE OF CONTENTS -------------------------------------------------------------------------------
Page Summary of the Offering..............................1 Risk Factors.........................................2 Additional Information...............................8 Forward Looking Statements and Associated Risks.............................................8 Investment Objectives................................9 Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners............10 Capitalization and Source of Funds and Use of Proceeds.........................................11 Compensation........................................14 Terms of the Offering...............................18 Prior Activities....................................22 Management..........................................29 Proposed Activities.................................33 Competition, Markets and Regulation.................96 Participation in Costs and Revenues.................99 Conflicts of Interest..............................103 Fiduciary Responsibility of the Managing General Partner.................................112 Tax Aspects........................................113 Summary of Partnership Agreement...................124 Summary of Drilling and Operating Agreement........126 Reports to Investors...............................127 Presentment Feature................................128 Transferability of Units...........................129 Plan of Distribution...............................130 Sales Material.....................................131 Legal Opinions.....................................132 Experts............................................132 Litigation.........................................132 Financial Information Concerning the Managing General Partner and the Partnership.............133
EXHIBIT (A) - Amended and Restated Certificate and Agreement of Limited Partnership EXHIBIT (I-A) - Managing General Partner Signature Page EXHIBIT (I-B) - Subscription Agreement EXHIBIT (II) - Drilling and Operating Agreement EXHIBIT (B) - Special Suitability Requirements and 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. ------------------------------------------------------------------------------- ------------------------------------------------------------------------------- ATLAS AMERICA PUBLIC #9 LTD. --------------- PROSPECTUS --------------- _____________, 2000 Until December 31, 2000, all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions. ------------------------------------------------------------------------------- PART II INFORMATION NOT REQUIRED IN PROSPECTUS ITEM 24. INDEMNIFICATION OF DIRECTORS AND OFFICERS. Section 1741 et seq. of the Pennsylvania Business Corporation Law provides for indemnification of officers, directors, employees and agents by a corporation subject to certain limitations. Under Section 4.05 of the Amended and Restated Certificate and Agreement of Limited Partnership, the Participants, within the limits of their Capital Contributions, and the Partnership, generally agree to indemnify and exonerate the Managing General Partner, the Operator and their Affiliates from claims of liability to any third party arising out of operations of the Partnership provided that: - they determined in good faith that the course of conduct which caused the loss or liability was in the best interest of the Partnership; - they were acting on behalf of or performing services for the Partnership; and - the course of conduct was not the result of their negligence or misconduct. Paragraph 11 of the Dealer-Manager Agreement provides for the indemnification of the Managing General Partner, the Partnership and control persons under specified conditions by the Dealer-Manager and/or Selling Agent. ITEM 25. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION. The expenses to be incurred in connection with the issuance and distribution of the securities to be registered, other than underwriting discounts, commissions and expense allowances, are estimated to be as follows: Accounting.................................................................................. $ 15,000.00* Legal Fees (including Blue Sky)............................................................. 75,000.00* Printing.................................................................................... 155,000.00* SEC Registration Fee........................................................................ 3,960.00 Blue Sky Filing Fees (excluding legal fees)................................................. 26,000.00* NASD Filing Fee............................................................................. 2,000.00 Miscellaneous............................................................................... 398,040.00* ------------ Total................................................. $675,000.00* ============
--------------- *Estimated ITEM 26. RECENT SALES OF UNREGISTERED SECURITIES. None by the Registrant. Atlas Resources, Inc. ("Atlas"), an Affiliate of the Registrant, has made sales of unregistered and registered securities within the last three years. See the section of the Prospectus captioned "Prior Activities" regarding the sale of limited and general partner interests. In the opinion of Atlas, the foregoing unregistered securities in each case have been and/or are being offered and sold in compliance with exemptions from registration provided by the Securities Act of 1933, as amended, including the exemptions provided by Section 4(2) of that Act and certain rules and regulations promulgated thereunder. The securities in each case have been and/or are being offered and sold to a limited number of persons who had the sophistication to understand the merits and risks of the investment and who had the financial ability to bear such risks. The units of limited and general partner interests were sold to persons who were Accredited Investors, as that term is defined in Regulation D (17 CFR 230.501(a)), or who had, at the time of purchase, a net worth of at least $225,000 (exclusive of home, furnishings and automobiles) or a net worth (exclusive of home, furnishings and automobiles) of at least $125,000 and gross income of at least $75,000, or otherwise satisfied Atlas that the investment was suitable. 1 ITEM 27. EXHIBITS. 1(a) Proposed form of Dealer-Manager Agreement with Anthem Securities, Inc. 1(b) Proposed form of Dealer-Manager Agreement with Bryan Funding, Inc. 3(a) Articles of Incorporation of Atlas Resources, Inc. 3(b) Bylaws of Atlas Resources, Inc. 4(a) Certificate of Limited Partnership for Atlas America Public #9 Ltd. 4(b) Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #9 Ltd. (See Exhibit (A) to Prospectus) 5 Opinion of Kunzman & Bollinger, Inc. as to the legality of the Units registered hereby 8 Opinion of Kunzman & Bollinger, Inc. as to tax matters 10(a) Escrow Agreement 10(b) Proposed Form of Drilling and Operating Agreement (See Exhibit (II) to the Amended and Restated Certificate and Agreement of Limited Partnership, Exhibit (A) to Prospectus) 24(a) Consent of Grant Thornton, L.L.P. 24(b) Consent of United Energy Development Consultants, Inc. 24(c) Consent of Kunzman & Bollinger, Inc. (See Exhibits 5 and 8) 24(d) Consent of Wright & Company, Inc. 25 Power of Attorney
ITEM 28. UNDERTAKINGS. (a) As required by Item 512(a) of Regulation S-B and Rule 415, the undersigned Registrant hereby undertakes: (1) to file, during any period in which offers or sales are being made, a Post-Effective Amendment to this Registration Statement to: (i) include any Prospectus required by Section 10(a)(3) of the Securities Act of 1933; (ii) reflect in the Prospectus any facts or events arising after the effective date of the Registration Statement (or of the most recent Post-Effective Amendment thereof) which, individually or together, represent a fundamental change in the information set forth in the Registration Statement; and (iii) include any material information with respect to the plan of distribution not previously disclosed in the Registration Statement or any material change to such information in the Registration Statement; (2) that, for the purpose of determining any liability under the Securities Act of 1933, each such Post-Effective Amendment shall be deemed to be a new Registration Statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof; and (3) to remove from registration by means of a Post-Effective Amendment any of the securities being registered which remain unsold at the termination of the offering. 2 (e) The undersigned Registrant undertakes: (1) insofar as indemnification for liabilities arising under the Securities Act of 1933 (the "Act") may be permitted to Atlas and its directors, officers and controlling persons pursuant to the foregoing provisions, or otherwise, Atlas and the Registrant have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by Atlas and its directors, officers and controlling persons in the successful defense of any action, suit or proceeding) is asserted by such party in connection with the securities being registered, Registrant will unless in the opinion of its counsel the matter has been settled by controlling precedent submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act, and will be governed by final adjudication of such issue. 3 SIGNATURES In accordance with the requirements of the Securities Act of 1933, the Registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form SB-2 and has authorized this Pre-Effective Amendment No. 1 to the Registration Statement to be signed on its behalf by the undersigned, thereto duly authorized, in Moon Township, Pennsylvania, on the 5th day of September, 2000. ATLAS AMERICA PUBLIC #9 LTD. (Registrant) By: Atlas Resources, Inc., Managing General Partner James R. O'Mara and Tony C. Banks, By: /s/ James R. O'Mara pursuant to the Registration Statement, ------------------------------- have been granted Power of Attorney and are James R. O'Mara, President, signing on behalf of the names shown below, Chief Executive Officer in the capacities indicated. and Director By: /s/ Tony C. Banks ------------------------------- Tony C. Banks, Senior Vice President, Chief Financial Officer and Director In accordance with the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities and on the dates indicated.
Signature Title Date --------- ----- ---- James R. O'Mara President, Chief Executive Officer and a Director September 5, 2000 Tony C. Banks Senior Vice President, Chief Financial Officer and a Director September 5, 2000 Michael L. Staines Senior Vice President and Chief Operating Officer September 5, 2000 Frank P. Carolas Vice President of Land and Geology September 5, 2000 Barbara J. Krasnicki Secretary September 5, 2000
EXHIBIT INDEX
Exhibit No. Description Page ----------- ----------- ---- 1(a) Proposed form of Dealer-Manager Agreement for Anthem Securities, Inc.* ________ 1(b) Proposed form of Dealer-Manager Agreement for Bryan Funding, Inc.* ________ 3(a) Articles of Incorporation of Atlas Resources, Inc.* ________ 3(b) Bylaws of Atlas Resources, Inc.* ________ 4(a) Certificate of Limited Partnership for Atlas America Public #9 Ltd.* ________ 4(b) Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #9 Ltd. (See Exhibit (A) to Prospectus) ________ 5 Opinion of Kunzman & Bollinger, Inc. as to the legality of the Units registered hereby* ________ 8 Opinion of Kunzman & Bollinger, Inc. as to tax matters* ________ 10(a) Escrow Agreement* ________ 10(b) Proposed form of Drilling and Operating Agreement (See Exhibit (II) to the Amended and Restated Certificate and Agreement of Limited Partnership, Exhibit (A) to Prospectus) ________ 24(a) Consent of Grant Thornton, L.L.P. ________ 24(b) Consent of United Energy Development Consultants, Inc.* ________ 24(c) Consent of Kunzman & Bollinger, Inc. (See Exhibits 5 and 8) ________ 24(d) Consent of Wright & Company, Inc.* ________ 25 Power of Attorney* ________
--------------- *Previously submitted.