-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, C9RuhQX15dGe8qd335zlQTzW9NWb5+B7JQOP/Juj9rdXX/oIIfnND1rI5m5tqs34 WdP9VWb9HLOkpdJZ6/Fhcw== 0000950116-04-002029.txt : 20040630 0000950116-04-002029.hdr.sgml : 20040630 20040630171737 ACCESSION NUMBER: 0000950116-04-002029 CONFORMED SUBMISSION TYPE: S-1 PUBLIC DOCUMENT COUNT: 17 FILED AS OF DATE: 20040630 FILER: COMPANY DATA: COMPANY CONFORMED NAME: Atlas America Public # 14-2004 Program CENTRAL INDEX KEY: 0001294476 IRS NUMBER: 000000000 FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: S-1 SEC ACT: 1933 Act SEC FILE NUMBER: 333-117035 FILM NUMBER: 04892123 BUSINESS ADDRESS: STREET 1: 311 ROUSER ROAD CITY: MOON TOWNSHIP STATE: PA ZIP: 15108 BUSINESS PHONE: 412-262-2830 MAIL ADDRESS: STREET 1: 311 ROUSER ROAD CITY: MOON TOWNSHIP STATE: PA ZIP: 15108 S-1 1 s1.txt S-1 As filed with the Securities and Exchange Commission on June 30, 2004 Registration Number _____________ - -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ____________________________________ FORM S-1 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 ____________________________________ ATLAS AMERICA PUBLIC #14-2004 PROGRAM (Exact name of Registrant as Specified in its Charter) DELAWARE (State or other jurisdiction of incorporation or organization) ____________________________________ 1311 (Primary Standard Industrial Classification Code Number) ____________________________________ NOT APPLICABLE (IRS Employer Identification Number) ____________________________________ 311 ROUSER ROAD MOON TOWNSHIP, PENNSYLVANIA 15108 (412) 262-2830 (Address, including zip code, and telephone number, including area code, of registrant's principal executive offices) ____________________________________ JACK L. HOLLANDER, SENIOR VICE PRESIDENT - DIRECT PARTICIPATION PROGRAMS ATLAS RESOURCES, INC. 311 ROUSER ROAD, MOON TOWNSHIP, PENNSYLVANIA 15108 (412) 262-2830 (Name, address, including zip code, and telephone number, including area code, of agent for service) ____________________________________ With a Copy to: WALLACE W. KUNZMAN, JR., ESQ. KUNZMAN & BOLLINGER, INC. 5100 N. BROOKLINE SUITE 600 OKLAHOMA CITY, OKLAHOMA 73112 ____________________________________ AS SOON AS PRACTICABLE AFTER THIS REGISTRATION STATEMENT BECOMES EFFECTIVE. (Approximate Date of Commencement of Proposed Sale to the Public) 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| If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. |_| If this Form is a post-effective amendment filed pursuant to rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. |_| If this Form is a post-effective amendment filed pursuant to rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. |_| If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box: |_| ____________________________________
CALCULATION OF REGISTRATION FEE - ------------------------------------------------------------------------------------------------------------------------------------ - ------------------------------------------------------------------------------------------------------------------------------------ Title of Each Unit Dollar Proposed Maximum Proposed Maximum Amount of Class of Securities Amounts Amounts to be Offering Aggregate Registration to be Registered to be Registered Registered Price per Unit Offering Price Fee - ------------------------------------------------------------------------------------------------------------------------------------ Investor General Partner Units (1) 11,875 $118,750,000 $10,000 $118,750,000 $15,045.63 Converted Limited Partner Units (2) 11,875 - 0 - - 0 - - 0 - - 0 - Limited Partner Units (2) 625 $6,250,000 $10,000 $6,250,000 $791.88 ------ ------------ ------- ------------ ---------- TOTAL 12,500 $125,000,000 $125,000,000 $15,837.51 ====== ============ ============ ==========
(1) "Investor General Partner Units" means the investor general partner interests offered to participants in the program. (2) "Limited Partner Units" means up to 625 initial limited partner interests offered to participants in the program and up to 11,875 limited partner units into which the investor general partner units automatically will be converted by the managing general partner with no additional price paid by the investor. THE REGISTRANT HEREBY AMENDS THIS 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 #14-2004 PROGRAM CROSS REFERENCE SHEET Item of Form S-1 Caption in Prospectus ---------------- --------------------- Item 1. Forepart of the Registration Statement and Outside Front Front Page of Registration Statement and Outside Front Cover Page of Prospectus................................... Cover Page of Prospectus Item 2. Inside Front and Outside Back Cover Pages of Prospectus.... Inside Front and Outside Back Cover Pages of Prospectus Item 3. Summary Information, Risk Factors and Ratio Of Earnings to Fixed Charges........................................... Summary of the Offering; Risk Factors Item 4. Use of Proceeds............................................ Capitalization and Source of Funds and Use of Proceeds Item 5. Determination of Offering Price............................ Terms of the Offering The partnership has not conducted any activities and the managing general partner's officers, directors, promoters and affiliated persons have not acquired any units during the past five years. Also, no units will be issued in this offering to the managing general partner except units subscribed for by the managing general partner, which it does not anticipate. Discounted units, if any, are described in "Plan of Item 6. Dilution................................................... Distribution." The partnership does not have any selling security Item 7. Selling Security Holders................................... holders. Item 8. Plan of Distribution....................................... Plan of Distribution Summary of the Offering; Terms of the Offering; Summary Item 9. Description of Securities to be Registered................. of Partnership Agreement Item 10. Interests of Named Experts and Counsel..................... Legal Opinions; Experts Item 11. Information with respect to the Registrant (a) Description of Business.............................. Proposed Activities; Management (b) Description of Property.............................. Proposed Activities (c) Legal Proceedings.................................... Litigation The partnership has no markets in which its units are (d) Market Price of and Dividends on the Registrant's being traded, no holders of units, and it has not Common Equity and Related Stockholder Matters........ conducted activities or paid any dividends. Financial Information Concerning the Managing General (e) Financial Statements................................. Partner Only the first partnership composing the program has been formed, and none of the partnerships have conducted any activities. Thus, the program does not have this (f) Selected Financial Data.............................. information. Only the first partnership composing the program has been formed, and none of the partnerships have conducted any activities. Thus, the program does not have this (g) Supplementary Financial Information.................. information.
Management's Discussion and Analysis of Financial (h) Management's Discussion and Analysis of Financial Condition, Results of Operations, Liquidity and Capital Condition and Results of Operations.................. Resources (i) Changes in and Disagreements with Accountants on There have been no changes in and disagreements with Accounting and Financial Disclosure.................. accountants on accounting and financial disclosure. (j) Quantitative and Qualitative Disclosures about The partnerships have no market for their units and none Market Risk.......................................... will be created. (k) Directors and Executive Officers..................... Management (l) Executive Compensation............................... Management (m) Security Ownership of Certain Beneficial Owners and Management....................................... Management (n) Certain Relationships and Related Transactions....... Compensation; Management; Conflicts of Interest Item 12. Disclosure of Commission Position on Indemnification Fiduciary Responsibilities of the Managing General for Securities Act Liabilities............................. Partner
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 Securities and Exchange Commission 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 JUNE 30, 2004 (Subject To Completion) ATLAS AMERICA PUBLIC #14-2004 PROGRAM o Up to 11,875 Investor General Partner Units and 11,875 converted Limited Partner Units and up to 625 Limited Partner Units, which are collectively referred to as the "Units," at $10,000 per Unit o $2 Million (200 Units) Minimum Aggregate Subscriptions o $125 Million (12,500 Units) Maximum Aggregate Subscriptions o Atlas America Public #14-2004 Program is a series o The Offering: In addition to the information in the table below of up to three limited partnerships which will for not less than 95% (11,875) of the units, up to 5% (625) of the drill primarily natural gas development wells. They units, in the aggregate, may be sold at $8,950 per unit to the will be managed by Atlas Resources, Inc. of managing general partner, its officers, directors and affiliates, Pittsburgh, Pennsylvania. and investors who buy units through the officers and directors of o If you invest in a partnership, then you will not the managing general partner; or at $9,300 per unit to registered have any interest in any of the other partnerships investment advisors and their clients, and selling agents and unless you also make a separate investment in the their registered representatives and principals. These discounted other partnerships. prices reflect certain fees, sales commissions and reimbursements o The units will be offered on a "best efforts" which will not be paid for these sales. (See "Plan of "minimum-maximum" basis. This means the Distribution.") To the extent that units are sold at discounted broker/dealers must sell at least 200 units and prices, a partnership's subscription proceeds will be reduced. receive subscription proceeds of at least $2 (See "Risk Factors - Risks Related to an Investment In a million in order for a partnership to close, and Partnership - Spreading the Risks of Drilling Among a Number of they must use only their best efforts to sell the Wells Will be Reduced if Less than the Maximum Subscription remaining units in the partnership. Proceeds are Received and Fewer Wells are Drilled.") o Subscription proceeds for each partnership will be held in an interest bearing escrow account until $2 Total Total million has been received. The offering of the Per Unit Minimum Maximum partnership designated Atlas America Public -------- ------- ------- #14-2004 L.P. will not extend beyond December 31, Public Price $ 10,000 $2,000,000 $125,000,000 2004, and the offering of any partnership designated Atlas America #14-2005(___) L.P. will Dealer-manager fee, not extend beyond December 31, 2005. If the minimum sales commissions, subscription proceeds are not received by a accountable partnership's offering termination date, then your reimbursements for subscription will be promptly returned to you from permissible non-cash the escrow account with interest and without compensation, and deduction for any fees. accountable due diligence reimbursements (1) $ 1,050 $ 210,000 $ 13,125,000 Proceeds to partnership $ 10,000 $2,000,000 $125,000,000 -------- (1) These fees, sales commissions and reimbursements will be paid by the managing general partner as a part of its capital contrib and not from subscription proceeds.
o A partnership's drilling operations involve the possibility of a substantial or partial loss of your investment because of wells which are productive, but do not produce enough revenue to return the investment made and dry holes. o A partnership's revenues are directly related to the ability to market the natural gas and natural gas and oil prices, which are volatile and uncertain. If natural gas and oil prices decrease, then your investment return will decrease. o Unlimited joint and several liability for partnership obligations if you choose to invest as an investor general partner until you are converted to a limited partner. o Lack of liquidity or a market for the units. o Lack of conflict of interest resolution procedures. o Total reliance on the managing general partner and its affiliates. o Authorization of substantial fees to the managing general partner and its affiliates. o You and the managing general partner will share in costs disproportionately to your sharing of revenues. o Possible allocation of taxable income to you in excess of your cash distributions from your partnership. o No guaranty of cash distributions every quarter. THESE SECURITIES ARE SPECULATIVE AND ARE SUBJECT TO CERTAIN RISKS. YOU SHOULD PURCHASE THESE SECURITIES ONLY IF YOU CAN AFFORD A COMPLETE LOSS OF YOUR INVESTMENT. (SEE "RISK FACTORS," PAGE 8.) Neither the SEC nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense. ANTHEM SECURITIES, INC. - DEALER-MANAGER BRYAN FUNDING, INC. - DEALER-MANAGER IN MINNESOTA AND NEW HAMPSHIRE TABLE OF CONTENTS SUMMARY OF THE OFFERING....................................................1 Business of the Partnerships and the Managing General Partner ............................................................1 Risk Factors...........................................................1 Terms of the Offering..................................................2 Description of Units...................................................3 Investor General Partner Units......................................3 Limited Partner Units...............................................4 Use of Proceeds........................................................5 Subordination, Participation in Costs and Revenues, and Distributions ......................................................5 Compensation...........................................................7 RISK FACTORS...............................................................8 Risks Related To The Partnerships' Oil and Gas Operations .........................................................8 No Guarantee of Return of Investment or Rate of Return on Investment Because of Speculative Nature of Drilling Natural Gas and Oil Wells.....................8 Because Some Wells May Not Return Their Drilling and Completion Costs, It May Take Many Years to Return Your Investment in Cash, If Ever.......................8 Nonproductive Wells May be Drilled Even Though the Partnerships' Operations are Primarily Limited to Development Drilling..........................................8 Partnership Distributions May be Reduced if There is a Decrease in the Price of Natural Gas and Oil ..................8 Adverse Events in Marketing a Partnership's Natural Gas Could Reduce Partnership Distributions ......................9 Possible Leasehold Defects..........................................9 Transfer of the Leases Will Not Be Made Until Well is Completed ...................................................10 Participation with Third-Parties in Drilling Wells May Require the Partnerships to Pay Additional Costs ..........................................................10 Risks Related to an Investment In a Partnership.......................10 If You Choose to Invest as a General Partner, Then You Have Greater Risk Than a Limited Partner ...................10 The Managing General Partner May Not Meet Its Capital Contributions, Indemnification and Purchase Obligations If Its Liquid Net Worth Is Not Sufficient...............................................11 An Investment in a Partnership Must be for the Long- Term Because the Units Are Illiquid and Not Readily Transferable............................................11 Spreading the Risks of Drilling Among a Number of Wells Will be Reduced if Less than the Maximum Subscription Proceeds are Received and Fewer Wells are Drilled ..............................................12 The Partnerships Do Not Own Any Prospects, the Managing General Partner Has Complete Discretion to Select Which Prospects Are Acquired By a Partnership, and The Possible Lack of Information for a Majority of the Prospects Decreases Your Ability to Evaluate the Feasibility of a Partnership ...............................................12 Drilling Prospects in One Area May Increase Risk ..................13 Lack of Production Information Increases Your Risk and Decreases Your Ability to Evaluate the Feasibility of a Partnership's Drilling Program ................13 The Partnerships Composing This Program and Other Partnerships Sponsored by the Managing General Partner May Compete With Each Other for Prospects, Equipment, Contractors, and Personnel ......................................................13 Managing General Partner's Subordination is Not a Guarantee of the Return of Any of Your Investment .....................................................13 Borrowings by the Managing General Partner Could Reduce Funds Available for Its Subordination Obligation........................................14 Compensation and Fees to the Managing General Partner Regardless of Success of a Partnership's Activities Will Reduce Cash Distributions...................................................14 The Intended Quarterly Distributions to Investors May be Reduced or Delayed ......................................14 There Are Conflicts of Interest Between the Managing General Partner and the Investors .....................14 The Presentment Obligation May Not Be Funded and the Presentment Price May Not Reflect Full Value .....................................................15 The Managing General Partner May Not Devote the Necessary Time to the Partnerships Because Its Management Obligations Are Not Exclusive.......................................................16 Prepaying Subscription Proceeds to the Managing General Partner May Expose the Subscription Proceeds to Claims of the Managing General Partner's Creditors ............................................16 Lack of Independent Underwriter May Reduce Due Diligence Investigation of the Partnerships and the Managing General Partner.........................................................16 A Lengthy Offering Period May Result in Delays in the Investment of Your Subscription and Any Cash Distributions From the Partnership to You..........................................................16 Tax Risks.............................................................16 Changes in the Law May Reduce to Some Degree Your Tax Benefits From an Investment in a Partnership ....................................................16 You May Owe Taxes in Excess of Your Cash Distributions from a Partnership ...............................16 Your Deduction for Intangible Drilling Costs May Be Limited for Purposes of the Alternative Minimum Tax ....................................................17 Investment Interest Deductions of Investor General Partners May Be Limited.................................17 Lack of Tax Shelter Registration Could Result in Penalties to You ...............................................17 ADDITIONAL INFORMATION....................................................17 FORWARD LOOKING STATEMENTS AND ASSOCIATED RISKS..........................................................17 INVESTMENT OBJECTIVES.....................................................18 ACTIONS TO BE TAKEN BY MANAGING GENERAL PARTNER TO REDUCE RISKS OF ADDITIONAL PAYMENTS BY INVESTOR GENERAL PARTNERS ....................................19 CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS.......................................................21 Source of Funds.......................................................21 Use of Proceeds.......................................................22 COMPENSATION..............................................................25 Natural Gas and Oil Revenues..........................................25 Lease Costs...........................................................26 Drilling Contracts....................................................26 ii TABLE OF CONTENTS Per Well Charges......................................................28 Gathering Fees........................................................29 Dealer-Manager Fees...................................................30 Interest and Other Compensation.......................................30 Estimate of Administrative Costs and Direct Costs to be Borne by the Partnerships .........................................30 TERMS OF THE OFFERING.....................................................31 Subscription to a Partnership.........................................31 Partnership Closings and Escrow.......................................32 Acceptance of Subscriptions...........................................33 Activation of the Partnerships........................................34 Suitability Standards.................................................34 In General.........................................................34 General Suitability Requirements for Purchasers of Limited Partner Units ..........................................34 Special Suitability Requirements for Purchasers of Limited Partner Units in California, Michigan, New Hampshire, North Carolina, Ohio and Pennsylvania ...................................................35 General Suitability Requirements for Purchasers of Investor General Partner Units .................................36 Special Suitability Requirements for Purchasers of Investor General Partner Units in either: (i) Alabama, Arkansas, Maine, Massachusetts, Minnesota, North Carolina, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, or Washington; or (ii) Arizona, Indiana, Iowa, Kansas, Kentucky, Michigan, Mississippi, Missouri, New Mexico, Oregon, South Dakota, or Vermont .............................. 36 Special Suitability Requirements for Purchasers of Investor General Partner Units in either California or New Hampshire.....................................38 Fiduciary Accounts and Confirmations...............................38 PRIOR ACTIVITIES..........................................................38 MANAGEMENT................................................................49 Managing General Partner and Operator.................................49 Officers, Directors and Other Key Personnel...........................50 Atlas America, Inc., a Delaware Holding Company.......................53 Organizational Diagram and Security Ownership of Beneficial Owners .................................................54 Remuneration..........................................................55 Code of Business Conduct and Ethics...................................55 Transactions with Management and Affiliates...........................55 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, RESULTS OF OPERATIONS, LIQUIDITY AND CAPITAL RESOURCES ..........................................55 PROPOSED ACTIVITIES.......................................................57 Overview of Drilling Activities.......................................57 Primary Areas of Operations...........................................58 Mississippian/Upper Devonian Sandstone Reservoirs, Fayette County, Pennsylvania........................59 Clinton/Medina Geological Formation in Western Pennsylvania ...................................................59 Upper Devonian Sandstone Reservoirs, Armstrong County, Pennsylvania ...........................................60 Upper Devonian Sandstone Reservoirs in McKean County, Pennsylvania .......................................... 60 Secondary Areas of Operations.........................................61 Clinton/Medina Geological Formation in Western New York.............................................61 Clinton/Medina Geological Formation in Southern Ohio................................................61 Acquisition of Leases.................................................62 Deep Drilling Rights Retained by Managing General Partner ................................................63 Interests of Parties..................................................63 Primary Areas.........................................................64 Clinton/Medina Geological Formation in Western Pennsylvania and Mississippian/Upper Devonian Sandstone Reservoirs in Fayette and Greene Counties, Pennsylvania and Upper Devonian Sandstone Reservoirs in McKean County, Pennsylvania ......................64 Upper Devonian Sandstone Reservoirs in Armstrong County, Pennsylvania .................................64 Secondary Areas.......................................................64 Title to Properties...................................................65 Drilling and Completion Activities; Operation of Producing Wells.................................................65 Sale of Natural Gas and Oil Production................................66 Policy of Treating All Wells Equally in a Geographic Area.................................................66 Gathering of Natural Gas...........................................67 Natural Gas Contracts..............................................67 Marketing of Natural Gas Production from Wells in Other Areas of the United States ..................................69 Crude Oil.............................................................70 Insurance.............................................................70 Use of Consultants and Subcontractors.................................70 COMPETITION, MARKETS AND REGULATION.......................................70 Natural Gas Regulation................................................70 Crude Oil Regulation..................................................71 Competition and Markets...............................................71 State Regulations.....................................................73 Environmental Regulation..............................................73 Proposed Regulation...................................................74 PARTICIPATION IN COSTS AND REVENUES.......................................74 In General............................................................74 Costs.................................................................74 Revenues..............................................................76 Subordination of Portion of Managing General Partner's Net Revenue Share........................................77 Table of Participation in Costs and Revenues..........................78 Allocation and Adjustment Among Investors.............................79 Distributions.........................................................80 Liquidation...........................................................80 CONFLICTS OF INTEREST.....................................................81 In General............................................................81 Conflicts Regarding Transactions with the Managing General Partner and its Affiliates ................................81 Conflict Regarding the Drilling and Operating Agreement..........................................................82 Conflicts Regarding Sharing of Costs and Revenues ....................82 Conflicts Regarding Tax Matters Partner...............................82 Conflicts Regarding Other Activities of the Managing General Partner, the Operator and Their Affiliates ................83 Conflicts Involving the Acquisition of Leases.........................83 Conflicts Between Investors and the Managing General Partner as an Investor ....................................87 Lack of Independent Underwriter and Due Diligence Investigation .....................................................88 Conflicts Concerning Legal Counsel....................................88 Conflicts Regarding Presentment Feature...............................88 Conflicts Regarding Managing General Partner Withdrawing an Interest ...........................................88 iii TABLE OF CONTENTS Conflicts Regarding Order of Pipeline Construction and Gathering Fees ....................................................89 Procedures to Reduce Conflicts of Interest............................89 Policy Regarding Roll-Ups.............................................90 FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER..................................................91 In General............................................................91 Limitations on Managing General Partner Liability as Fiduciary .........................................................92 MATERIAL FEDERAL INCOME TAX CONSEQUENCES..................................93 Summary of Tax Opinion................................................93 Summary Discussion of the Material Federal Income Tax Consequences of an Investment in a Partnership ................96 In General............................................................96 Partnership Classification............................................96 Limitations on Passive Activities.....................................96 Publicly Traded Partnership Rules..................................97 Conversion from Investor General Partner to Limited Partner.........................................................97 Taxable Year and Method of Accounting.................................97 2004 and 2005 Expenditures............................................98 Availability of Certain Deductions....................................98 Intangible Drilling Costs.............................................98 Drilling Contracts....................................................99 Depletion Allowance..................................................101 Depreciation - Modified Accelerated Cost Recovery System ("MACRS")..................................................101 Lease Acquisition Costs and Abandonment..............................102 Tax Basis of Units...................................................102 "At Risk" Limitation for Losses......................................102 Distributions from a Partnership.....................................103 Sale of the Properties...............................................103 Disposition of Units.................................................103 Alternative Minimum Tax..............................................104 Limitations on Deduction of Investment Interest......................106 Allocations..........................................................106 Partnership Borrowings...............................................107 Partnership Organization and Offering Costs..........................107 Tax Elections........................................................107 Termination of a Partnership.........................................107 Lack of Registration as a Tax Shelter................................108 Investor Lists....................................................108 Tax Returns and IRS Audits...........................................108 In General........................................................108 Tax Returns.......................................................108 Penalties and Interest...............................................108 In General........................................................108 Penalty for Negligence or Disregard of Rules or Regulations....................................................109 Valuation Misstatement Penalty....................................109 Substantial Understatement Penalty................................109 Profit Motive, IRS Anti-Abuse Rule and Judicial Doctrines .....................................................109 State and Local Taxes................................................110 Severance and Ad Valorem (Real Estate) Taxes.........................110 Social Security Benefits and Self-Employment Tax.....................110 Farmouts.............................................................110 Foreign Partners.....................................................111 Estate and Gift Taxation.............................................111 Changes in the Law...................................................111 SUMMARY OF PARTNERSHIP AGREEMENT.........................................111 Liability of Limited Partners........................................111 Amendments...........................................................111 Notice...............................................................112 Voting Rights........................................................112 Access to Records....................................................113 Withdrawal of Managing General Partner...............................113 Return of Subscription Proceeds if Funds Are Not Invested in Twelve Months ........................................113 SUMMARY OF DRILLING AND OPERATING AGREEMENT................................................................113 REPORTS TO INVESTORS.....................................................114 PRESENTMENT FEATURE......................................................115 TRANSFERABILITY OF UNITS.................................................117 Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement.........................................................117 Conditions to Becoming a Substitute Partner..........................118 PLAN OF DISTRIBUTION.....................................................118 Commissions..........................................................118 Indemnification......................................................121 SALES MATERIAL...........................................................121 LEGAL OPINIONS...........................................................122 EXPERTS..................................................................122 LITIGATION...............................................................123 FINANCIAL INFORMATION CONCERNING THE MANAGING GENERAL PARTNER AND ATLAS AMERICA PUBLIC #14-2004 L.P..........................................123 Exhibits Appendix A Information Regarding Currently Proposed Prospects for Atlas America Public #14-2004 L.P. Exhibit (A) Form of Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #14-2004 L.P. [Form of Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #14-2005(_____) L.P.] Exhibit (I-A) Form of Managing General Partner Signature Page Exhibit (I-B) Form of Subscription Agreement Exhibit (II) Form of Drilling and Operating Agreement for Atlas America Public #14-2004 L.P. [Atlas America Public #14-2005(_____) L.P.] Exhibit (B) Special Suitability Requirements and Disclosures to Investors iv SUMMARY OF THE OFFERING This is a summary and does not include all of the information which may be important to you. You should read the entire prospectus and the attached exhibits and appendix before you decide to invest. Throughout this prospectus when there is a reference to you it is a reference to you as a potential investor or participant in a partnership. BUSINESS OF THE PARTNERSHIPS AND THE MANAGING GENERAL PARTNER Atlas America Public #14-2004 Program, which is sometimes referred to in this prospectus as the "program," consists of up to three Delaware limited partnerships. These limited partnerships are sometimes referred to in this prospectus in the singular as a "partnership" or in the plural as the "partnerships." Units of the various partnerships will be offered and sold in a series during a portion of 2004 and 2005. See "Terms of the Offering" for a discussion of the terms and conditions involved in making an investment in a partnership. Each of the program's partnerships will be a separate business entity from the other partnerships. A limited partnership agreement will govern the rights and obligations of the partners of each partnership. A form of the limited partnership agreement is attached to this prospectus as Exhibit (A). For a summary of the material provisions of the limited partnership agreement which are not covered elsewhere in this prospectus see "Summary of Partnership Agreement." You will be a partner only in the partnership in which you invest. You will have no interest in the business, assets or tax benefits of the other partnerships unless you also invest in the other partnerships. Thus, your investment return will depend solely on the operations and success or lack of success of the partnership in which you invest. The offering proceeds of each partnership will be used to drill primarily natural gas development wells in the Appalachian Basin located in western Pennsylvania, eastern and southern Ohio and western New York as described in "Proposed Activities." A development well means a well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive. Currently, the partnerships do not hold any interests in any properties or prospects on which the wells will be drilled. The managing general partner of each partnership is or will be Atlas Resources, Inc., a Pennsylvania corporation, which was incorporated in 1979, and is sometimes referred to in this prospectus as "Atlas Resources." As set forth in "Prior Activities," the managing general partner has sponsored and serves as managing general partner of 34 private drilling partnerships which raised a total of $195,300,802, and 12 public drilling partnerships which raised a total of $167,610,898. Atlas Resources also will serve as each partnership's general drilling contractor and operator and supervise the drilling, completing and operating of the wells to be drilled. As of March 1, 2004, the managing general partner and its affiliates operated approximately 4,653 natural gas and oil wells located in Ohio, Pennsylvania and New York. The address and telephone number of the partnerships and the managing general partner are 311 Rouser Road, Moon Township, Pennsylvania 15108, (412) 262-2830. RISK FACTORS This offering involves numerous risks, including risks related to each partnership's oil and gas operations, risks related to a partnership investment, and tax risks. You should carefully consider a number of significant risk factors inherent in and affecting the business of a partnership and this offering, including the following. o Each partnership's drilling operations involve the possibility of a substantial or partial loss of your investment because of wells which are productive, but do not produce enough revenue to return the investment made and from time to time dry holes. o Each partnership's revenues are directly related to the ability to market the natural gas and natural gas and oil prices, which are volatile and uncertain, and if natural gas and oil prices decrease then your investment return will decrease. 1 o Unlimited joint and several liability for partnership obligations if you choose to invest as an investor general partner until you are converted to a limited partner. o Lack of liquidity or a market for the units, necessitating a long-term commitment. o Total reliance on the managing general partner and its affiliates. o Authorization of substantial fees to the managing general partner and its affiliates. o Possible allocation of taxable income to investors in excess of their cash distributions from a partnership. o Each partnership must receive minimum subscriptions of $2 million to close, and the subscription proceeds of all partnerships, in the aggregate, may not exceed $125 million. There are no other requirements regarding the size of a partnership, and the subscription proceeds of one partnership may be substantially more or less than the subscription proceeds of the other partnerships. If only the minimum subscriptions are received in a partnership, the partnership's ability to spread the risks of drilling will be greatly reduced as described in "Compensation - Drilling Contracts." o Certain conflicts of interest between the managing general partner and you and the other investors and lack of procedures to resolve the conflicts. o You and the other investors and the managing general partner will share in costs disproportionately to the sharing of revenues. o Currently, the partnerships do not hold any interests in any properties or prospects on which the wells will be drilled. Although the managing general partner has absolute discretion in determining which properties or prospects will be drilled by a partnership, the managing general partner intends that Atlas America Public #14-2004 L.P., which must close on or before December 31, 2004, will drill the prospects described in "Appendix A - Information Regarding Currently Proposed Prospects for Atlas America Public #14-2004 L.P." These prospects represent a portion of the wells to be drilled if the nonbinding targeted subscription proceeds described in "Terms of the Offering - Subscription to a Partnership" are received. If there are adverse events with respect to any of the currently proposed prospects, the managing general partner will substitute the partnership's prospects. The managing general partner also anticipates that it will designate a portion of the prospects in each partnership designated Atlas America Public #14-2005(_____) L.P. by a supplement or an amendment to the registration statement of which this prospectus is a part. o In each partnership the managing general partner may subordinate a portion of its share of that partnership's net production revenues. This subordination is not a guaranty by the managing general partner, and if the wells in that partnership produce small volumes of natural gas and oil and/or natural gas and oil prices decrease, then even with subordination your cash flow from the partnership may not return your entire investment. o In each partnership quarterly cash distributions to investors may be deferred if revenues are used for partnership operations or reserves. TERMS OF THE OFFERING The offering period will begin on the date of this prospectus. Each partnership will offer a minimum of 200 units, which is $2 million, and all partnerships, in the aggregate, will offer a maximum of 12,500 units which is $125 million. The maximum subscription proceeds for each partnership will be the lesser of: 2 o the registered amount of $125 million; or o the number of units which remain unsold from the $125 million aggregate registration. The targeted subscription proceeds and closing date for each partnership, which are not binding on the managing general partner, are set forth in a table in "Terms of the Offering - Subscription to a Partnership." Units are offered at a subscription price of $10,000 per unit, provided that up to 5% of the units sold, in the aggregate, may be sold to certain investors at discounts as described in "Plan of Distribution." All subscriptions must be paid 100% in cash at the time of subscribing. Your minimum subscription in a partnership is one unit; however, the managing general partner, in its discretion, may accept one-half unit subscriptions from you at any time. Larger fractional subscriptions will be accepted in $1,000 increments, beginning, for example, with either $11,000, $12,000, etc. if you pay $10,000 for a full unit, or $6,000, $7,000, etc. if you pay $5,000 for a one-half unit. You will have the election to purchase units as either an investor general partner or a limited partner as described in "- Description of Units," below. Under the partnership agreement no investor, including investor general partners, may participate in the management of a partnership's business. The managing general partner will have exclusive management authority for the partnerships. Subscription proceeds for a partnership will be held in a separate interest bearing escrow account at National City Bank of Pennsylvania until receipt of the minimum subscription proceeds. Each partnership is or will be formed as a limited partnership under the Delaware Revised Uniform Limited Partnership Act before breaking escrow. In addition, a partnership may not break escrow as described in "Terms of the Offering - Partnership Closings and Escrow," unless the partnership is in receipt of the minimum subscription proceeds after the discounts described in "Plan of Distribution" and excluding any subscriptions by the managing general partner or its affiliates. However, on receipt of the minimum subscription proceeds, the managing general partner on behalf of a partnership may break escrow, transfer the escrowed funds to a partnership account, and begin its activities, including drilling to the extent the prospects have been identified in this prospectus or by a supplement or an amendment to the registration statement. After breaking escrow additional subscription proceeds may be paid directly to the partnership account for that partnership and will continue to earn interest until the offering closes. (See "Terms of the Offering.") DESCRIPTION OF UNITS In the partnership being offered at the time you subscribe you may buy either: o investor general partner units; or o limited partner units. The first partnership, Atlas America Public #14-2004 L.P., has been formed as a Delaware limited partnership. However, the other partnerships have not yet been formed. The units offered in those partnerships in 2005 may be preformation investor general partner interests and preformation limited partner interests which will become units of investor general partner interests or limited partner interests, respectively, in the particular partnership if it has not been formed at the time you subscribe. The type of unit you buy will not affect the allocation of costs, revenues, and cash distributions among you and the other investors. There are, however, material differences in the federal income tax effects and liability associated with each type of unit. INVESTOR GENERAL PARTNER UNITS. o TAX EFFECT. If you invest in a partnership as an investor general partner, then your share of the partnership's deduction for intangible drilling costs will not be subject to the passive activity limitation on losses because your investor general partner units will not be converted to limited partner units until after all the wells have been drilled and completed. For example, if you pay $10,000 for a unit, then generally you may deduct approximately 90% of your subscription, $9,000, in the year in which you invest, which includes your deduction for intangible drilling costs for all of the wells to be drilled by the partnership. (See "Material Federal Income Tax Consequences - Limitations on Passive Activities.") 3 o 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. o LIABILITY. If you invest in a partnership as an investor general partner, then you will have unlimited liability regarding the partnership's activities. This means if: o the insurance proceeds; o the managing general partner's indemnification; and o the partnership's assets 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 require you and the other investor general partners to make additional capital contributions to the partnership to satisfy the liability. In addition, you and the other investor general partners 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. (See "Actions To Be Taken By Managing General Partner To Reduce Risks of Additional Payments by Investor General Partners" and "Proposed Activities - Insurance.") Although past performance is no guarantee of future results, the investor general partners in the managing general partner's prior partnerships have not had to make additional capital contributions to their partnerships because of their status as investor general partners. Your investor general partner units in a partnership will be automatically converted by the managing general partner to limited partner units after all of the partnership wells have been drilled and completed. The conversion will not create any tax liability to you or the other investors. Once your units are converted you will have the lesser liability of a limited partner under Delaware law for obligations and liabilities arising after the conversion. However, you will continue to have the responsibilities of a general partner for partnership liabilities and obligations incurred before the effective date of the conversion. For example, you might become liable for partnership liabilities in excess of your subscription 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. LIMITED PARTNER UNITS. o TAX EFFECT. If you invest in a partnership as a limited partner, then the use of your share of the partnership's deduction for intangible drilling costs will be limited to net passive income from "passive" trade or business activities. Passive trade or business activities generally include the partnership and other limited partner investments, but passive income does not include dividends and interest. This means that you will not be able to deduct your share of the partnership's intangible drilling costs in the year in which you invest unless you have passive income from investments other than the partnership. (See "Material Federal Income Tax Consequences - Limitations on Passive Activities.") 4 o LIABILITY. If you invest in a partnership as a limited partner, then you will have limited liability. This means you will not be liable for amounts beyond your initial investment and share of undistributed net profits, subject to certain exceptions set forth in "Summary of Partnership Agreement - Liability of Limited Partners." USE OF PROCEEDS Each partnership must receive minimum subscription proceeds of $2 million to close, and the subscription proceeds of all partnerships, in the aggregate, may not exceed $125 million. The subscription proceeds of one partnership may be substantially more or less than the subscription proceeds of the other partnerships. The subscription proceeds of each partnership, regardless of whether the number of units sold to you and the other investors in a partnership is the minimum or up to the maximum, will be used to pay: o 100% of the intangible drilling costs, which is defined above in "- Description of Units"; and o 34% of the equipment costs of drilling and completing the partnership's wells, but not to exceed 10% of the partnership's subscription proceeds. The managing general partner will contribute all of the leases to each partnership covering the acreage on which each partnership's wells will be drilled and pay: o 66% of the equipment costs of drilling and completing the partnership's wells; and o any equipment costs that exceed 10% of the partnership's subscription proceeds that would otherwise be charged to you and the other investors. The managing general partner also will be charged with 100% of the organization and offering costs for each partnership. A portion of these contributions to each partnership will be in the form of payments to itself, its affiliates and third-parties and the remainder will be in the form of services related to organizing this offering. The managing general partner will receive a credit towards its required capital contribution to each partnership for these payments and services as discussed in "Participation in Costs and Revenues." (See "Capitalization and Source of Funds and Use of Proceeds" and "Material Federal Income Tax Consequences - Intangible Drilling Costs.") SUBORDINATION, PARTICIPATION IN COSTS AND REVENUES, AND DISTRIBUTIONS Each partnership will be a separate business entity from the other partnerships, and you will be a partner only in the partnership in which you invest. You will have no interest in the business, assets or tax benefits of the other partnerships unless you also invest in the other partnerships. Thus, your investment return will depend solely on the operations and success or lack of success of the particular partnership in which you invest. Each partnership is structured to provide you and the other investors with cash distributions equal to a minimum of 10% per unit, based on $10,000 per unit regardless of the actual subscription price for your units, in each of the first five 12-month periods beginning with the partnership's first cash distributions from operations. To help achieve this investment feature the managing general partner will subordinate up to 50% of its share of partnership net production revenues during this subordination period. 5 Each partnership's 60-month subordination period will begin with the partnership's first cash distribution from operations to you and the other investors. However, no subordination distributions to you and the other investors will be required until the partnership's first cash distribution after substantially all of the partnership wells have been drilled, completed, and begun producing into a sales line. Subordination distributions will be determined by debiting or crediting current period partnership revenues to the managing general partner as may be necessary to provide the distributions to you and the other investors. At any time during the subordination period, but not after, the managing general partner is entitled to an additional share of partnership revenues to recoup previous subordination distributions to the extent your cash distributions from the partnership exceed the 10% return of capital described above. The specific formula is set forth in Section 5.01(b)(4)(a) of the partnership agreement. The following table sets forth the partnership costs and revenues charged and credited between the managing general partner and you and the other investors for each partnership after deducting from the partnership's gross revenues the landowner royalties and any other lease burdens.
MANAGING GENERAL PARTNER INVESTORS PARTNERSHIP COSTS -------- --------- Organization and offering costs.....................................................100% 0% Lease costs.........................................................................100% 0% Intangible drilling costs.............................................................0% 100% Equipment costs (1)..................................................................66% 34% Operating costs, administrative costs, direct costs, and all other costs.....................................................................(2) (2) PARTNERSHIP REVENUES Interest income......................................................................(3) (3) Equipment proceeds (1)...............................................................66% 34% All other revenues including production revenues..................................(4)(5) (4)(5)
- ---------------- (1) These percentages may vary. If the total equipment costs for all of a partnership's wells that would be charged to you and the other investors exceeds an amount equal to 10% of the subscription proceeds of you and the other investors in the partnership, then the excess will be charged to the managing general partner. Equipment proceeds, if any, will be credited in the same percentage in which the equipment costs were charged. (2) These costs will be charged to the parties in the same ratio as the related production revenues are being credited. These costs also include the plugging and abandonment costs of the wells as described in "Participation in Costs and Revenues." (3) Interest earned on your subscription proceeds before the final closing of the partnership to which you subscribed will be credited to your account and paid not later than the partnership's first cash distributions from operations. After each closing of a partnership and until the subscription proceeds from the closing are invested in the partnership's natural gas and oil operations any interest income from temporary investments will be allocated pro rata to the investors providing the subscription proceeds. All other interest income, including interest earned on the deposit of operating revenues, will be credited as natural gas and oil production revenues are credited. (4) The managing general partner and the investors in a partnership will share in all of that partnership's other revenues in the same percentage as their respective capital contributions bears to the total partnership capital contributions except that the managing general partner will receive an additional 7% of the partnership revenues. However, the managing general partner's total revenue share may not exceed 35% of partnership revenues. (5) The actual allocation of partnership revenues between the managing general partner and the investors will vary from the allocation described in (4) above if a portion of the managing general partner's partnership net production revenues is subordinated as described above. 6 The managing general partner will review a partnership's accounts at least quarterly to determine whether cash distributions are appropriate and the amount to be distributed, if any. The partnership in which you invest will distribute funds to you and the other investors that the managing general partner does not believe are necessary for the partnership to retain. (See "Participation in Costs and Revenues.") COMPENSATION The items of compensation paid to the managing general partner and its affiliates from each partnership are as follows: o The managing general partner will receive a share of each partnership's revenues. The managing general partner's revenue share will be in the same percentage as its capital contribution bears to that partnership's total capital contributions plus an additional 7% of partnership revenues, but not to exceed a total of 35% of partnership revenues, regardless of the amount of the managing general partner's capital contribution, subject to the managing general partner's subordination obligation. o The managing general partner will receive a credit to its capital account equal to the cost of the leases or the fair market value of the leases if the managing general partner has reason to believe that cost is materially more than the fair market value. o Each 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%. The cost of the well includes reimbursement from the investors to the managing general partner of its general and administrative overhead which cannot exceed $13,307 per well. o When the wells for a partnership begin producing the managing general partner, as operator of the wells, will receive: o reimbursement at actual cost for all direct expenses incurred on behalf of the partnership; and o well supervision fees for operating and maintaining the wells during producing operations at a competitive rate. o The managing general partner will receive gathering fees at competitive rates. o Subject to certain exceptions described in "Plan of Distribution," Anthem Securities, Inc., the dealer-manager and an affiliate of the managing general partner, which is sometimes referred to in this prospectus as "Anthem Securities," will receive on each unit sold to an investor a 2.5% dealer-manager fee, a 7% sales commission, a .5% accountable reimbursement for permissible non-cash compensation, and up to a .5% reimbursement of the selling agents' bona fide accountable due diligence expenses. o The managing general partner or an affiliate will have the right to charge a competitive rate of interest on any loan it may make to or on behalf of a partnership. If the managing general partner provides equipment, supplies, and other services to a partnership, then it may do so at competitive industry rates. o 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. The managing general partner may not increase this fee during the term of the partnership. (See "Compensation.") 7 RISK FACTORS An investment in a partnership involves a high degree of risk and is suitable only if you have substantial financial means and no need of liquidity in your investment. RISKS RELATED TO THE PARTNERSHIPS' OIL AND GAS OPERATIONS NO GUARANTEE OF RETURN OF INVESTMENT OR RATE OF RETURN ON INVESTMENT BECAUSE OF SPECULATIVE NATURE OF DRILLING NATURAL GAS AND OIL WELLS. Natural gas and oil exploration is an inherently speculative activity. Before the drilling of a well the managing general partner cannot predict with absolute certainty: o the volume of natural gas and oil recoverable from the well; or o the time it will take to recover the natural gas and oil. You may not recover all of your investment in a partnership, or if you do recover your investment in a partnership you may 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 natural gas and oil from productive wells. The quantity of natural gas and oil in a well, which is referred to as its reserves, decreases over time as the natural gas and oil is produced until the well is no longer economical to operate. All of these distributions to you will be considered a return of capital until you have received 100% of your investment. This means that you are not receiving a return on your investment in a partnership, excluding tax benefits, until your total cash distributions from the partnership exceed 100% of your investment. (See "Prior Activities.") BECAUSE SOME WELLS MAY NOT RETURN THEIR DRILLING AND COMPLETION COSTS, IT MAY TAKE MANY YEARS TO RETURN YOUR INVESTMENT IN CASH, IF EVER. Even if a well is completed in a partnership and produces natural gas and oil in commercial quantities, it may not produce enough natural gas and oil to pay for the costs of drilling and completing the well, even if tax benefits are considered. For example, the managing general partner has formed 46 partnerships since 1985, however, 36 of the 46 partnerships have not yet returned to the investor 100% of his capital contributions without taking tax savings into account. Thus, it may take many years to return your investment in cash, if ever. (See "Prior Activities.") NONPRODUCTIVE WELLS MAY BE DRILLED EVEN THOUGH THE PARTNERSHIPS' OPERATIONS ARE PRIMARILY LIMITED TO DEVELOPMENT DRILLING. Each partnership may drill some development wells which are nonproductive, which is referred to as a "dry hole," and must be plugged and abandoned. If one or more of the partnership's wells are nonproductive, then the partnership's productive wells may not produce enough revenues to offset the loss of investment in the nonproductive wells. (See "Prior Activities" and "Proposed Activities.") PARTNERSHIP DISTRIBUTIONS MAY BE REDUCED IF THERE IS A DECREASE IN THE PRICE OF NATURAL GAS AND OIL. The prices at which a partnership's natural gas and oil will be sold are uncertain and as discussed in "- Adverse Events in Marketing a Partnership's Natural Gas Could Reduce Partnership Distributions," the partnerships are not guaranteed a specific natural gas price for the sale of their natural gas production. Historically, natural gas and oil prices have been volatile and will likely continue to be volatile in the future. Prices for natural gas and oil will depend on supply and demand factors largely beyond the control of the partnership. For example, the demand for natural gas is usually greater in the winter months because of residential heating requirements than in the summer months, and generally results in lower natural gas prices in the summer months than in the winter months. See "Competition, Markets and Regulation - Competition and Markets" for other factors affecting the supply and demand of natural gas and oil. These factors make it extremely difficult to predict natural gas and oil price movements with any certainty. If natural gas and oil prices decrease in the future, then your partnership distributions will decrease accordingly. Also, natural gas and oil prices may decrease during the first years of production from your partnership's wells which is when the wells typically achieve their greatest level of production. This would have a greater adverse effect on your partnership distributions than price decreases in later years when the wells have a lower level of production. (See "Appendix A - Information Regarding Currently Proposed Prospects for Atlas America Public #14-2004 L.P." for a discussion of flush production and "Proposed Activities - Sale of Natural Gas and Oil Production.") 8 ADVERSE EVENTS IN MARKETING A PARTNERSHIP'S NATURAL GAS COULD REDUCE PARTNERSHIP DISTRIBUTIONS. In addition to the risk of decreased natural gas and oil prices described above, there are risks associated with marketing natural gas which could reduce a partnership's distributions to you and the other investors. These risks are set forth below. o Competition from other natural gas producers and marketers in the Appalachian Basin as well as competition from alternative energy sources may make it more difficult to market each partnership's natural gas. o The majority of each partnership's natural gas production will be sold to two different natural gas purchasers as described in "Proposed Activities - Sale of Natural Gas and Oil Production." One of the natural gas purchasers has a 10-year agreement, which began on April 11, 1999, to buy all of the managing general partner's and its affiliates', which includes the partnerships, natural gas production, subject to various exceptions. The most significant exception from this agreement for the partnerships is for natural gas produced from Fayette County, which is where the managing general partner anticipates that the majority of the prospects which will be drilled by each partnership will be situated if the targeted nonbinding subscription proceeds described in "Terms of the Offering - Subscription to a Partnership" for each partnership are reached. The majority, if not all, of the natural gas produced from Fayette County will be sold to one purchaser under a natural gas contract which ends March 31, 2006. Both of these contracts provide that the price may be adjusted upward or downward in accordance with the spot market price and market conditions as described in "Proposed Activities - Sale of Natural Gas and Oil Production." Thus, the partnerships will depend primarily on two natural gas purchasers and will not be guaranteed a specific natural gas price, other than through hedging. The price for each partnership's natural gas may decrease in the future because of market conditions. Also, even though hedging provides the partnerships some protection against falling natural gas prices, hedging also could reduce the potential benefits of price increases if at the time the natural gas is to be delivered the spot market natural gas price is higher than the price paid under the hedging arrangement. o There is a credit risk associated with a natural gas purchaser's ability to pay. Each partnership may not be paid or may experience delays in receiving payment for natural gas that has already been delivered. In accordance with industry practice, a partnership typically will deliver natural gas to a purchaser for a period of up to 60 to 90 days before it receives payment. Thus, it is possible that the partnership may not be paid for natural gas that already has been delivered if the natural gas purchaser fails to pay for any reason, including bankruptcy. This ongoing credit risk also may delay or interrupt the sale of the partnership's natural gas or its negotiation of different terms and arrangements for selling its natural gas to other purchasers. Finally, this credit risk may reduce the price benefit derived by the partnerships from the managing general partner's natural gas hedging as described in "Proposed Activities - Sale of Natural Gas and Oil Production - Natural Gas Contracts," since the majority of the managing general partner's natural gas hedges are implemented through the natural gas purchasers. o Partnership revenues may be less the farther the natural gas is transported because of increased transportation costs. o Production from wells drilled in certain areas, such as the wells in Crawford County, Pennsylvania and to a lesser extent, Fayette County, Pennsylvania, may be delayed until construction of the necessary gathering lines and production facilities is completed. (See "Proposed Activities - Sale of Natural Gas and Oil Production.") POSSIBLE LEASEHOLD DEFECTS. There may be defects in a partnership's title to its leases. Although the managing general partner will obtain a favorable formal title opinion for the leases before each well is drilled, it will not obtain a division order title opinion after the well is completed. A partnership may experience losses from title defects which arose during drilling that would have been disclosed by a division order title opinion, such as liens that may arise during drilling or transfers made after drilling begins. Also, 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. (See "Proposed Activities - Title to Properties.") 9 TRANSFER OF THE LEASES WILL NOT BE MADE UNTIL WELL IS COMPLETED. Because the leases will not be transferred from the managing general partner to a partnership until after the wells are drilled and completed, the transfer could be set aside by a creditor of the managing general partner, or the trustee in the event of the voluntary or involuntary bankruptcy of the managing general partner, if it were determined that the managing general partner received less than a reasonably equivalent value for the leases. In this event, the leases and the wells would revert to the creditors or trustee, and the partnership would either recover nothing or only the amount paid for the leases and the cost of drilling the wells. Assigning the leases to a partnership after the wells are drilled and completed, however, will not affect the availability of the tax deductions for intangible drilling costs since the partnership will have an economic interest in the wells under the drilling and operating agreement before the wells are drilled. (See "Proposed Activities - Title to Properties.") PARTICIPATION WITH THIRD-PARTIES IN DRILLING WELLS MAY REQUIRE THE PARTNERSHIPS TO PAY ADDITIONAL COSTS. Third-parties will participate with each partnership in drilling some of the wells. Financial risks exist when the cost of drilling, equipping, completing, and operating wells is shared by more than one person. If a partnership pays its share of the costs, but another interest owner does not pay its share of the costs, then the partnership would have to pay the costs of the defaulting party. In this event, the partnership would receive the defaulting party's revenues from the well, if any, under penalty arrangements set forth in the operating agreement. If the managing general partner is 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. For example, decisions related to the following would be made by the third-party operator and may not be in the best interests of the partnerships and you and the other investors: o how the well is operated; o expenditures related to the well; and o possibly the marketing of the natural gas and oil production. Further, the third-party operator may have financial difficulties and fail to pay for materials or services on the wells it drills or operates, which would cause the partnership to incur extra costs in discharging materialmen's and workmen's liens. The managing general partner may not be the operator of the well if the partnership owns less than a 50% working interest in the well, or if the managing general partner acquired the working interest in the well from a third-party which required that the third-party be named operator as one of the terms of the acquisition. RISKS RELATED TO AN INVESTMENT IN A PARTNERSHIP IF YOU CHOOSE TO INVEST AS A GENERAL PARTNER, 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 Delaware law you will have unlimited liability for your partnership's activities until converted to limited partner status subject to certain exceptions as described in "Actions To Be Taken by Managing General Partner To Reduce Risks of Additional Payments By Investor General Partners - Conversion of Investor General Partner Units to Limited Partner Units." This could result in you being required to make payments, in addition to your original investment, in amounts that are impossible to predict because of their uncertain nature. Under the terms of the partnership agreement, if you are an investor general partner you agree to pay only your proportionate share of your partnership's obligations and liabilities. This agreement, however, does not eliminate your liability to third-parties if another investor general partner does not pay his proportionate share of your partnership's obligations and liabilities. Also, each partnership will own less than 100% of the working interest in some of its wells. If a court holds you and the other third-party working interest owners of the well liable for the development and operation of a well and the third-party working interest owners do not pay their proportionate share of the costs and liabilities associated with the well, then the partnership and you and the other investor general partners also would be liable for those costs and liabilities. As an investor general partner you may become subject to the following: o contract liability, which is not covered by insurance; 10 o liability for pollution, abuses of the environment, and other environmental damages such as the release of toxic gas, spills or uncontrollable flows of natural gas, oil or fluids, 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 o liability for drilling hazards which result in property damage, personal injury, or death to third-parties in amounts greater than the insurance coverage. The drilling hazards include, but are not limited to well blowouts, fires, and explosions. If your partnership's insurance proceeds and assets, the managing general partner's indemnification of you and the other investor general partners, and the liability coverage provided by major subcontractors were not sufficient to satisfy the liability, then the managing general partner would call for additional funds from you and the other investor general partners to satisfy the liability. (See "Actions To Be Taken By Managing General Partner To Reduce Risks of Additional Payments by Investor General Partners.") THE MANAGING GENERAL PARTNER MAY NOT MEET ITS CAPITAL CONTRIBUTIONS, INDEMNIFICATION AND PURCHASE OBLIGATIONS IF ITS LIQUID NET WORTH IS NOT SUFFICIENT. The managing general partner has made commitments to you and the other investors in each partnership regarding the following: o the payment of organization and offering costs and the majority of equipment costs; o indemnification of the investor general partners for liabilities in excess of their pro rata share of partnership assets and insurance proceeds; and o purchasing units presented by an investor, although this may be suspended by the managing general partner if it determines, in its sole discretion, that it does not have the necessary cash flow or cannot borrow funds for this purpose on reasonable terms. A significant financial reversal for the managing general partner could adversely affect its ability to honor these obligations. The managing general partner's net worth is based primarily on the estimated value of its producing natural gas properties and is not available in cash without borrowings or a sale of the properties. Also, if natural gas prices decrease, then the estimated value of the properties and the managing general partner's net worth will be reduced. Further, price decreases will reduce the managing general partner's revenues, and may make some reserves uneconomic to produce. This would reduce the managing general partner's reserves and cash flow, and could cause the lenders of the managing general partner and its affiliates to reduce the borrowing base for the managing general partner and its affiliates. Also, because approximately 92% of the managing general partner's proved reserves are currently natural gas reserves, the managing general partner's net worth is more susceptible to movements in natural gas prices than in oil prices. The managing general partner's net worth may not be sufficient, either currently or in the future, to meet its financial commitments under the partnership agreement. These risks are increased because the managing general partner has made similar financial commitments in 41 other partnerships and will make this same commitment in future partnerships. (See "Financial Information Concerning the Managing General Partner and Atlas America Public #14-2004 L.P.") AN INVESTMENT IN A PARTNERSHIP MUST BE FOR THE LONG-TERM BECAUSE THE UNITS ARE ILLIQUID AND NOT READILY TRANSFERABLE. If you invest in a partnership, then you must assume the risks of an illiquid investment. The transferability of the units is limited by the federal securities laws, the tax laws, and the partnership agreement. The units generally cannot be liquidated since there is not a readily available market for the sale of the units. Further, the partnerships do not intend to register the units and list the units on any exchange. 11 Finally, a sale of your units could create adverse tax and economic consequences for you. The sale or exchange of all or part of your units held for more than 12 months generally will result in a recognition of long-term capital gain or loss. However, previous deductions for depreciation, depletion and IDCs may be recaptured as ordinary income rather than capital gain regardless of how long you have owned the units. If the units are held for 12 months or less, then the gain or loss generally will be short-term gain or loss. Your pro rata share of a partnership's liabilities, if any, as of the date of the sale or exchange must be included in the amount realized by you. Thus, the gain recognized by you may result in a tax liability greater than the cash proceeds, if any, received by you from the sale or other taxable disposition of your units. (See "Material Federal Income Tax Consequences-Disposition of Units" and "Presentment Feature.") SPREADING THE RISKS OF DRILLING AMONG A NUMBER OF WELLS WILL BE REDUCED IF LESS THAN THE MAXIMUM SUBSCRIPTION PROCEEDS ARE RECEIVED AND FEWER WELLS ARE DRILLED. Each partnership must receive minimum subscription proceeds of $2 million to close, and the subscription proceeds of all of the partnerships, in the aggregate, may not exceed $125 million. There are no other requirements regarding the size of a partnership other than the nonbinding targeted amounts described in "Terms of the Offering - Subscription to a Partnership," and the subscription proceeds of one partnership may be substantially more or less than the subscription proceeds of another partnership. A partnership with a smaller amount of subscription proceeds will drill fewer wells which decreases the partnership's ability to spread the risks of drilling. For example, the managing general partner anticipates that a partnership will drill approximately ___ net wells if the minimum subscriptions of $2 million are received, which is compared with ___ net wells if subscription proceeds of $125 million are received by a partnership. A gross well is a well in which a partnership owns a working interest. This is compared with a net well which is the sum of the fractional working interests owned in the gross wells. For example, a 50% working interest owned in three wells is three gross wells, but 1.5 net wells. On the other hand, to the extent more than the minimum subscriptions are received by a partnership and the number of wells drilled increases, the partnership's overall investment return may decrease if the managing general partner is unable to find enough suitable wells to be drilled. Also, in a large partnership greater demands will be placed on the managing general partner's management capabilities. Finally, the cost of drilling and completing a well is often uncertain and there may be cost overruns in drilling and completing the wells because the wells will not be drilled and completed on a turnkey basis for a fixed price, which would shift the risk of loss to the managing general partner as drilling contractor. The majority of the equipment costs of a partnership's wells, including any equipment costs in excess of 10% of the partnership's subscription proceeds, will be paid by the managing general partner. However, all of the intangible drilling costs will be charged to you and the other investors. If there is a cost overrun for the intangible drilling costs of a well or wells, then the managing general partner anticipates that it would use the subscription proceeds, if available, to pay the cost overrun or advance the necessary funds to the partnership. Using subscription proceeds to pay cost overruns will result in a partnership drilling fewer wells. Also, unanticipated costs can adversely affect the economics of a well. For example, the managing general partner and its affiliates have experienced an increase in the cost of tubular steel as a result of rising steel prices which may increase well costs. THE PARTNERSHIPS DO NOT OWN ANY PROSPECTS, THE MANAGING GENERAL PARTNER HAS COMPLETE DISCRETION TO SELECT WHICH PROSPECTS ARE ACQUIRED BY A PARTNERSHIP, AND THE POSSIBLE LACK OF INFORMATION FOR A MAJORITY OF THE PROSPECTS DECREASES YOUR ABILITY TO EVALUATE THE FEASIBILITY OF A PARTNERSHIP. The partnerships do not currently hold any interests in any prospects on which the wells will be drilled, and the managing general partner has absolute discretion in determining which prospects will be acquired to be drilled. The managing general partner has identified in "Proposed Activities" the general areas where each partnership will drill wells and the managing general partner intends that Atlas America Public #14-2004 L.P., which must close on or before December 31, 2004, will drill the prospects described in "Appendix A - Information Regarding Currently Proposed Prospects for Atlas America Public #14-2004 L.P." These prospects represent the wells currently proposed to be drilled if a portion of the targeted nonbinding amount of subscription proceeds is received as described in "Terms of the Offering - Subscription to a Partnership." If there are adverse events with respect to any of the currently proposed prospects, the managing general partner will substitute the partnership's prospects. The managing general partner also anticipates that it will designate a portion of the prospects in each partnership designated Atlas America Public #14-2005(_____) L.P. by a supplement or an amendment to the registration statement of which this prospectus is a part. With respect to the identified prospects for a partnership, the managing general partner has the right on behalf of the partnership to: 12 o substitute prospects; o take a lesser working interest in the prospects; o drill in other areas; or o do any combination of the foregoing. Thus, you do not have any geological or production information to evaluate any additional and/or substituted prospects and wells. Also, if the subscription proceeds received in a partnership are insufficient to drill all of the identified prospects, then the managing general partner will choose those prospects which it believes are most suitable for the partnership. You must rely entirely on the managing general partner to select the prospects and wells for a partnership. Finally, the partnerships do not have the right of first refusal in the selection of prospects from the inventory of the managing general partner and its affiliates, and they may sell their prospects to other partnerships, companies, joint ventures, or other persons at any time. DRILLING PROSPECTS IN ONE AREA MAY INCREASE RISK. To the extent that the prospects are drilled in one area at the same time, this may increase the risk of loss. For example, if multiple wells in one area are drilled at approximately the same time, then there is a greater risk of loss if the wells are marginal or nonproductive since the managing general partner will not be using the drilling results of one or more of those wells to decide whether or not to continue drilling prospects in that area or to substitute other prospects in other areas. This is compared with the situation in which the managing general partner drills one well and assesses the drilling results before it decides to drill a second well in the same area or to substitute a different prospect in another area. This risk is further increased with wells which are prepaid because of the 90 day time constraint and potential adverse weather conditions where the managing general partner is required to drill many wells at the same time. For example, "frost laws" prohibit drilling rigs and other heavy equipment from using certain roads during the winter, which may delay drilling and completing wells within the 90 day time constraint. Also, there could be shortages of drilling rigs, equipment, supplies and personnel during this time period. (See "Material Federal Income Tax Consequences - Drilling Contracts.") LACK OF PRODUCTION INFORMATION INCREASES YOUR RISK AND DECREASES YOUR ABILITY TO EVALUATE THE FEASIBILITY OF A PARTNERSHIP'S DRILLING PROGRAM. Production information from surrounding wells in the area is an important indicator in evaluating the economic potential of a proposed well to be drilled. However, the data set forth in "Appendix A - Information Concerning Currently Proposed Wells for Atlas America Public #14-2004 L.P." for the proposed wells in Pennsylvania may not show all of the wells drilled and/or production from those wells because there was a third-party operator and the Pennsylvania Department of Environmental Resources keeps production data confidential for the first five years from the time a well starts producing. If the managing general partner is the operator and no production data is shown, it is because the wells are not yet completed, on-line to sell production, or have been producing for only a short period of time. This lack of production information from surrounding wells results in greater uncertainty to you and the other investors. THE PARTNERSHIPS COMPOSING THIS PROGRAM AND OTHER PARTNERSHIPS SPONSORED BY THE MANAGING GENERAL PARTNER MAY COMPETE WITH EACH OTHER FOR PROSPECTS, EQUIPMENT, CONTRACTORS, AND PERSONNEL. One or more partnerships in this program or other partnerships sponsored by the managing general partner may have unexpended capital funds at the same time. Thus, these partnerships may compete for suitable prospects and the availability of equipment, contractors, and the managing general partner's personnel. For example, a partnership previously organized by the managing general partner may still be acquiring prospects to drill when the partnerships composing this program are attempting to acquire prospects. This may make it more difficult to complete the prospect acquisition activities for the partnerships composing this program and may make each partnership less profitable. MANAGING GENERAL PARTNER'S SUBORDINATION IS NOT A GUARANTEE OF THE RETURN OF ANY OF YOUR INVESTMENT. If your cash distributions from the partnership in which you invest are less than a 10% return of capital for each of the first five 12-month periods beginning with the partnership's first cash distributions from operations, then the managing general partner has agreed to subordinate a portion of its share of the partnership's net production revenues. However, if the wells produce only small natural gas and oil volumes, and/or natural gas and oil prices decrease, then even with subordination you may not receive the 10% return of capital for each of the first five years as described above, or a return of your capital during the term of the partnership. Also, at any time during the subordination period the managing general partner is entitled to an additional share of partnership revenues to recoup previous subordination distributions to the extent your cash distributions from the partnership exceed the 10% return of capital described above. (See "Participation in Costs and Revenues - Subordination of Portion of the Managing General Partner's Net Revenue Share.") 13 BORROWINGS BY THE MANAGING GENERAL PARTNER COULD REDUCE FUNDS AVAILABLE FOR ITS SUBORDINATION OBLIGATION. With respect to each partnership, the managing general partner has or will pledge either its partnership interest and/or an undivided interest in the partnership's assets equal to or less than its revenue interest, which will range from 32% to 35% depending on the amount of its capital contribution, to secure borrowings for its and its affiliates' corporate purposes. (See "Participation in Costs and Revenues.") Under agreements previously entered into as described in "Management's Discussion and Analysis of Financial Condition, Results of Operations, Liquidity and Capital Resources," the managing general partner's lenders have required a first lien in the property and will have priority over the managing general partner's subordination obligation under each partnership agreement. Thus, if there was a default to the lenders under this pledge arrangement, this would reduce or eliminate the amount of each partnership's net production revenues available to the managing general partner for its subordination obligation to you and the other investors. Also, under certain circumstances, if the managing general partner made a subordination distribution to you and the other investors after a default to its lenders, then the lenders may be able to recoup that subordination distribution from you and the other investors. COMPENSATION AND FEES TO THE MANAGING GENERAL PARTNER REGARDLESS OF SUCCESS OF A PARTNERSHIP'S ACTIVITIES WILL REDUCE CASH DISTRIBUTIONS. The managing general partner and its affiliates will profit from their services in drilling, completing, and operating each partnership's wells, and will receive the other fees and reimbursement of direct costs described in "Compensation" regardless of the success of the partnership's wells. These fees and direct costs will reduce the amount of cash distributions to you and the other investors. The amount of the fees is subject to the complete discretion of the managing general partner other than the fees must not exceed competitive fees charged by unaffiliated third-parties in the same geographic area engaged in similar businesses and any other restrictions set forth in "Compensation." With respect to direct costs, the managing general partner has sole discretion on behalf of each partnership to select the provider of the services or goods and the provider's compensation as discussed in "Compensation." THE INTENDED QUARTERLY DISTRIBUTIONS TO INVESTORS MAY BE REDUCED OR DELAYED. Cash distributions to you and the other investors may not be paid each quarter. Distributions may be reduced or deferred, in the discretion of the managing general partner, to the extent a partnership's revenues are used for any of the following: o repayment of borrowings; o cost overruns; o remedial work to improve a well's producing capability; o direct costs and general and administrative expenses of the partnership; o reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells; or o indemnification of the managing general partner and its affiliates by the partnership for losses or liabilities incurred in connection with the partnership's activities. (See "Participation in Costs and Revenues - Distributions.") THERE ARE CONFLICTS OF INTEREST BETWEEN THE MANAGING GENERAL PARTNER AND THE INVESTORS. There are conflicts of interest between you and the managing general partner and its affiliates. These conflicts of interest, which are not otherwise discussed in this "Risk Factors" section, include the following: o the managing general partner has determined the compensation and reimbursement that it and its affiliates will receive in connection with the partnerships without any unaffiliated third-party dealing at arms' length on behalf of the investors; 14 o the managing general partner must monitor and enforce, on behalf of the partnerships, its own compliance with the drilling and operating agreement; o because the managing general partner will receive a percentage of revenues greater than the percentage of costs that it pays, there may be a conflict of interest concerning which wells will be drilled based on the wells' risk and profit potential; o the allocation of all intangible drilling costs to you and the other investors and the majority of the equipment costs to the managing general partner may create a conflict of interest concerning whether to complete a well; o if the managing general partner, as tax matters partner, represents a partnership before the IRS, potential conflicts include whether or not to expend partnership funds to contest a proposed adjustment by the IRS, if any, to the amount of your deduction for intangible drilling costs, or the credit to the managing general partner's capital account for contributing the leases to the partnership; o which wells will be drilled by the managing general partner's and its affiliates' other affiliated partnerships or third-party programs in which they serve as driller/operator and which wells will be drilled by the partnerships, and the terms on which the partnerships' leases will be acquired; o the terms on which the managing general partner or affiliated limited partnerships may purchase producing wells from each partnership; o the possible purchase of units by the managing general partner, its officers, directors, and affiliates for a reduced price which would dilute the voting rights of you and the other investors on certain matters; o the representation of the managing general partner and each partnership by the same legal counsel; o the right of Atlas Pipeline Partners to determine the order of priority for constructing gathering lines; o the benefits to Atlas Pipeline Partners of the managing general partner causing the partnerships to drill wells that will connect to the gathering system owned by Atlas Pipeline Partners; and o the obligation of the managing general partner's affiliates, which does not include the partnerships for this purpose, to pay Atlas Pipeline Partners the difference between the gathering fees to be paid by each partnership to the managing general partner and the greater of $.35 per mcf or 16% of the gross sales price for the gas as described in "Proposed Activities - Sale of Natural Gas and Oil Production - Gathering of Natural Gas." Other than certain guidelines set forth in "Conflicts of Interest," the managing general partner has no established procedures to resolve a conflict of interest. THE PRESENTMENT OBLIGATION MAY NOT BE FUNDED AND THE PRESENTMENT PRICE MAY NOT REFLECT FULL VALUE. Subject to certain conditions, beginning with the fifth calendar year after your partnership closes you may present your units to the managing general partner for purchase. However, the managing general partner may determine, in its sole discretion, that it does not have the necessary cash flow or cannot borrow funds for this purpose on reasonable terms. In either event the managing general partner may suspend the presentment feature. This risk is increased because the managing general partner has and will incur similar presentment obligations in other partnerships. Further, the presentment price may not reflect the full value of a partnership's property or your units because of the difficulty in accurately estimating natural gas and oil reserves. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way, and the accuracy of the reserve estimate is a function of the quality of the available data and of engineering and geological interpretation and judgment. Also, the reserves and future net revenues are based on various assumptions as to natural gas and oil prices, taxes, development expenses, capital expenses, operating expenses and availability of funds. Any significant variance in these assumptions could materially affect the estimated quantity of the reserves. As a result, the managing general partner's estimates are inherently imprecise and may not correspond to realizable value. The presentment price paid for your units and any revenues received by you before the presentment may not be equal to the purchase price of the units. Conversely, because the presentment price is a contractual price it is not reduced by discounts such as minority interests and lack of marketability that generally are used to value partnership interests for tax and other purposes. (See "Presentment Feature.") 15 Finally, see "- An Investment in a Partnership Must be for the Long-Term Because the Units Are Illiquid and Not Readily Transferable," above, concerning the tax effects of presenting your units for purchase. THE MANAGING GENERAL PARTNER MAY NOT DEVOTE THE NECESSARY TIME TO THE PARTNERSHIPS BECAUSE ITS MANAGEMENT OBLIGATIONS ARE NOT EXCLUSIVE. The managing general partner may not devote the necessary time to the partnerships. The managing general partner and its affiliates will be engaged in other oil and gas activities, including other partnerships and unrelated business ventures for their own account or for the account of others, during the term of each partnership. (See "Management.") PREPAYING SUBSCRIPTION PROCEEDS TO THE MANAGING GENERAL PARTNER MAY EXPOSE THE SUBSCRIPTION PROCEEDS TO CLAIMS OF THE MANAGING GENERAL PARTNER'S CREDITORS. Under the drilling and operating agreement each partnership will be required to immediately pay the managing general partner the investors' share of the entire estimated price for drilling and completing the partnership's wells. Thus, these funds could be subject to claims of the managing general partner's creditors. (See "Financial Information Concerning the Managing General Partner and Atlas America Public #14-2004 L.P.") LACK OF INDEPENDENT UNDERWRITER MAY REDUCE DUE DILIGENCE INVESTIGATION OF THE PARTNERSHIPS AND THE MANAGING GENERAL PARTNER. There has not been an extensive in-depth "due diligence" investigation of the existing and proposed business activities of the partnerships and the managing general partner that would be provided by independent underwriters. Anthem Securities, which is affiliated with the managing general partner, serves as dealer-manager and will receive reimbursement of accountable due diligence expenses for certain due diligence investigations conducted by the selling agents which it will reallow to the selling agents. However, its due diligence examination concerning the partnerships cannot be considered to be independent or as comprehensive as an investigation that would be conducted by an independent broker/dealer. (See "Conflicts of Interest.") A LENGTHY OFFERING PERIOD MAY RESULT IN DELAYS IN THE INVESTMENT OF YOUR SUBSCRIPTION AND ANY CASH DISTRIBUTIONS FROM THE PARTNERSHIP TO YOU. Because the offering period for a particular partnership can extend for many months, it is likely that there will be a delay in the investment of your subscription proceeds. This may create a delay in the partnership's cash distributions to you which will be paid only after payment of the managing general partner's fees and expenses and only if there is sufficient cash available. See "Terms of the Offering" for a discussion of the procedures involved in the offering of the units and the formation of a partnership. TAX RISKS CHANGES IN THE LAW MAY REDUCE TO SOME DEGREE YOUR TAX BENEFITS FROM AN INVESTMENT IN A PARTNERSHIP. Your investment in a partnership may be affected by changes in the tax laws. For example, in 2003 the top four federal income tax brackets for individuals were reduced, including reducing the top bracket to 35% from 38.6%, until December 31, 2010. The lower federal income tax rates will reduce to some degree the amount of taxes you save by virtue of your share of your partnership's deductions for intangible drilling costs, depletion, and depreciation. Also, the federal income tax rates described above may be changed again before January 1, 2011. YOU MAY OWE TAXES IN EXCESS OF YOUR CASH DISTRIBUTIONS FROM A PARTNERSHIP. You may become subject to income tax liability for partnership income in excess of the cash you actually receive from a partnership in which you invest. For example: o if a 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; 16 o income from sales of natural gas and oil may be accrued by a partnership in one tax year, although payment is not actually received by the partnership until the next tax year; o 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; o partnership revenues may be expended by the managing general partner for non-deductible costs or retained to establish a reserve for future estimated costs, including a reserve for the estimated costs of eventually plugging and abandoning the wells; and o the taxable disposition of partnership property or your units may result in income tax liability in excess of cash distributions. YOUR DEDUCTION FOR INTANGIBLE DRILLING COSTS MAY BE LIMITED FOR PURPOSES OF THE ALTERNATIVE MINIMUM TAX. You will be allocated a share of your partnership's deduction for intangible drilling costs. However, under current tax law your alternative minimum taxable income cannot be reduced by more than 40% by the deduction for intangible drilling costs. Also, if you invest as a limited partner you may not have enough passive income to use your share of a partnership's deduction for intangible drilling costs. INVESTMENT INTEREST DEDUCTIONS OF INVESTOR GENERAL PARTNERS MAY BE LIMITED. An investor general partner's share of a 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 COULD RESULT IN PENALTIES TO YOU. The managing general partner has determined that the partnerships are not tax shelters required to register with the IRS. If it is subsequently determined by the IRS or the courts that the partnerships were required to be registered with the IRS as tax shelters, then you would be liable for a $250 penalty for failure to include a tax registration number for your partnership on your individual federal income tax return, unless this failure was due to reasonable cause. ADDITIONAL INFORMATION The program and the partnerships composing the program currently are not required to file reports with the SEC. However, a registration statement on Form S-1 has been filed on behalf of the program with the SEC. Certain portions of the registration statement have been deleted from this prospectus under SEC rules and regulations. You are urged to refer to the registration statement and exhibits for further information concerning the provisions of certain documents referred to in this prospectus. You may read and copy any materials filed as a part of the registration statement, including the tax opinion included as Exhibit 8, 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 program. 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 partnerships anticipate will or may occur in the future. For example, the words "believes," "anticipates," and "expects" are intended to identify forward-looking statements. These forward-looking statements include such things as: o investment objectives; 17 o references to future success; o business strategy; o estimated future capital expenditures; o competitive strengths and goals; and o other similar matters. These statements are based on certain assumptions and analyses made by the partnerships and the managing general partner in light of their experience and their perception of historical trends, current conditions, and expected future developments. However, whether actual results will conform with these expectations is subject to a number of risks and uncertainties, many of which are beyond the control of the partnerships, including, but not limited to: o general economic, market, or business conditions; o changes in laws or regulations; o the risk that the wells are productive, but do not produce enough revenue to return the investment made; o the risk that the wells are dry holes; and o uncertainties concerning natural gas and oil prices, which could decrease in the future. 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 partnerships' expectations. INVESTMENT OBJECTIVES Each partnership's principal investment objectives are to invest its subscription proceeds in natural gas development wells which will: o Provide quarterly cash distributions to you from the partnership in which you invest until the wells are depleted with a minimum annual cash flow of 10% during the first five years beginning with your partnership's first revenue distribution based on $10,000 per unit for all units sold. These distributions of a 10% return of capital during the first five years are not guaranteed, but are subject to the managing general partner's subordination obligation. The managing general partner anticipates that investors in a partnership will begin to receive quarterly cash distributions approximately seven months after the offering period for the partnership ends. (See "Participation in Costs and Revenues - Subordination of Portion of Managing General Partner's Net Revenue Share.") The partnerships do not currently hold any interests in any prospects on which the wells will be drilled. o Obtain income tax deductions from the partnership in which you invest, in the year that you invest, from intangible drilling costs to offset a portion of your taxable income from sources other than the partnership, subject to the passive activity rules if you invest as a limited partner. For example, if you pay $10,000 for a unit your investment will produce an income tax deduction of approximately $9,000 per unit, 90%, in the year you invest against: o ordinary income, or capital gain in some situations, if you invest as an investor general partner in a partnership; and o passive income if you invest as a limited partner in a partnership. 18 In 2003, the top four tax brackets for individual taxpayers were reduced from 38.6% to 35%, 35% to 33%, 30% to 28%, and 27% to 25%. These changes are scheduled to expire December 31, 2010. If you are in either the 35% or 33% tax bracket, you will save approximately $3,150 or $2,970, respectively, per $10,000 unit, in federal income taxes in the year that you invest. Most states also allow this type of a deduction against the state income tax. If the partnership in which you invest begins selling natural gas and oil production from its wells in the year in which you invest, however, then you may be allocated a share of partnership income in that year which will be offset by a portion of your intangible drilling cost deduction and your share of the other partnership deductions discussed below. o Offset a portion of any gross production income generated by your partnership with tax deductions from percentage depletion, which is 15% in 2004. The percentage depletion rate may fluctuate from year to year depending on the price of oil, but under current tax law it will not be less than the statutory rate of 15% nor more than 25%. o Obtain income tax deductions of the remaining 10% of your investment over a seven-year cost recovery period, beginning in the year the wells are drilled, completed and placed in service for production of natural gas or oil. For example, if you pay $10,000 for a unit, you will receive additional income tax deductions which total approximately $1,000 per unit, in the aggregate, over the seven-year cost recovery period for depreciation of your partnership's equipment costs for its productive wells. o If you are self-employed and invest in a partnership as an investor general partner, then you may use your share of the partnership's deduction for intangible drilling costs to offset a portion of your net earnings from self-employment in the year you invest. Attainment of these investment objectives by a partnership will depend on many factors, including the ability of the managing general partner to select suitable wells that will be productive and produce enough revenue to return the investment made. The success of each partnership depends largely on future economic conditions, especially the future price of natural gas which is volatile and may decrease. Also, the extent to which each partnership attains the foregoing investment objectives will be different, because each partnership is a separate business entity which: o generally will drill different wells; o will likely receive a different amount of subscription proceeds, which generally will be the primary factor in determining the number of wells that can be drilled by each partnership; and o may drill wells situated in different geographical areas, where the wells will be drilled to different formations, reservoirs or depths, which will affect the cost of the wells and, thus, will also affect the number of wells that can be drilled by each partnership. There can be no guarantee that the foregoing objectives will be attained. ACTIONS TO BE TAKEN BY MANAGING GENERAL PARTNER TO REDUCE RISKS OF ADDITIONAL PAYMENTS BY INVESTOR GENERAL PARTNERS You may choose to invest in a partnership 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. 19 o INSURANCE. 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. Each partnership will be included as an insured under these general, umbrella, and excess liability policies. In addition, the managing general partner requires all of its subcontractors to certify that they have acceptable insurance coverage for worker's compensation and general, auto, and excess liability coverage. Major subcontractors are required to carry general and auto liability insurance with a minimum of $1 million combined single limit for bodily injury and property damage in any one occurrence or accident. In the event of a loss caused by a major subcontractor, the managing general partner or partnership may attempt to draw on the insurance policy of the particular subcontractor before the insurance of the managing general partner or that of the partnership, but currently would be unable to do so since none of its major subcontractors have insurance which would allow this. Also, even if a major subcontractor's insurance was initially available, the managing general partner or partnership may choose to draw on its own insurance coverage before that of the major subcontractor so that its insurance carrier will control the payment of claims. The managing general partner's current insurance coverage satisfies the following specifications: o 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; o commercial general liability covering bodily injury and property damage third party liability, including products/completed operations, blow out, cratering, and explosion with limits of $1 million per occurrence/$2 million general aggregate; and $1 million products/completed operations aggregate; o underground resources and equipment property damages liability to others with a limit of $1 million; o automobile liability with a $1 million combined single limit; o employer's liability with a $500,000 policy limit; o pollution liability resulting from a "pollution incident," which is defined as the discharge, dispersal, seepage, migration, release or escape of one or more pollutants directly from a well site, with a limit of $1 million for bodily injury and property damage and a limit of $100,000 for clean-up for third-parties; however, coverage does not apply to pollution damage to the well site itself or the property of the insured; o commercial umbrella liability composed of: o primary umbrella limit of $25 million over general liability, automobile liability, and employer's liability and a $10 million sublimit for pollution liability; and o excess liability providing excess limits of $24 million over the $25 million provided in the commercial umbrella, but excluding pollution liability. Because the managing general partner is driller and operator of other partnerships, the insurance available to each partnership could be substantially less if insurance claims are made in the other partnerships. This insurance has deductibles, which would first have to be paid by a partnership, of: o $2,500 per occurrence for bodily injury and property damage; and o $10,000 per pollution incident for pollution damage. 20 The insurance has terms, including exclusions, which are standard for the natural gas and oil industry. On request the managing general partner will provide you or your representative a copy of its insurance policies. The managing general partner will use its best efforts to maintain insurance coverage that meets its current coverage, but 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 a partnership's insurance coverage, which the managing general partner does not anticipate, then the managing general partner must notify you at least 30 days before the effective date of the change. You will have the right to convert your units into limited partner units before the change by giving written notice to the managing general partner. o CONVERSION OF INVESTOR GENERAL PARTNER UNITS TO LIMITED PARTNER UNITS. Your investor general partner units will be automatically converted by the managing general partner to limited partner units after all of the wells in your partnership have been drilled and completed. In each partnership, the managing general partner anticipates that the wells will be placed in service and conversion will occur no more than 12 months after a partnership closes. Once your units are converted, which is a nontaxable event, you will have the lesser liability of a limited partner in your partnership under Delaware law for obligations and liabilities arising after the conversion. However, you will continue to have the responsibilities of a general partner for partnership liabilities and obligations incurred before the effective date of the conversion. For example, you might become liable for partnership liabilities in excess of your subscription 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. o NONRECOURSE DEBT. The partnerships do not anticipate that they will borrow funds. However, if borrowings are required, then the partnerships will be permitted to borrow funds only from the managing general partner or its affiliates without recourse against 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 by a partnership will be repaid from that partnership's revenues. The amount that may be borrowed at any one time by a partnership may not exceed an amount equal to 5% of the investors' subscriptions in the partnership. However, because you do not bear the risk of repaying these borrowings with non-partnership assets, the borrowings will not increase the extent to which you are allowed to deduct your individual share of partnership losses. o INDEMNIFICATION. The managing general partner will indemnify you from any liability incurred in connection with your partnership that is in excess of your interest in the partnership's: o undistributed net assets; and o insurance proceeds, if any, from all potential sources. The managing general partner's indemnification obligation, however, will not eliminate your potential liability if the managing general partner's assets are insufficient to satisfy its indemnification obligation. There can be no assurance that the managing general partner's assets, including its liquid assets, will be sufficient to satisfy its indemnification obligation. 21 CAPITALIZATION AND SOURCE OF FUNDS AND USE OF PROCEEDS SOURCE OF FUNDS Each partnership must receive minimum subscription proceeds of $2 million to close, and the subscription proceeds of all partnerships, in the aggregate, may not exceed $125 million. There are no other requirements regarding the size of a partnership, and the subscription proceeds of one partnership may be substantially more or less than the subscription proceeds of the other partnerships. However, see "Terms of the Offering - Subscription to a Partnership" regarding the targeted nonbinding amount of subscription proceeds for each partnership. On completion of an offering for a partnership, the partnership's source of funds will be as follows assuming each unit is sold for $10,000: o the subscription proceeds of you and the other investors, which will be: o $2 million if 200 units are sold; and o $125 million if 12,500 units are sold; and o the managing general partner's capital contribution, which must be at least 25% of all capital contributions, and includes its credit for organization and offering costs and contributing the leases, which will be: o not less than $666,667 if 200 units are sold; and o not less than $41,666,667 if 12,500 units are sold. Thus, the total amount available to a partnership will be not less than $2,666,667 if 200 units are sold ranging to not less than $166,666,667 if 12,500 units are sold. The managing general partner has made the largest single capital contribution in each of its prior partnerships and no individual investor has contributed more, although the total investor contributions in each partnership have exceeded the managing general partner's contribution. The managing general partner expects to make the largest single capital contribution in each of the partnerships. USE OF PROCEEDS The subscription proceeds received from you and the other investors for a partnership will be used to pay: o 100% of the intangible drilling costs of drilling and completing that partnership's wells; and o 34% of the equipment costs of drilling and completing that partnership's wells, but not to exceed 10% of that partnership's subscription proceeds. The managing general partner will contribute all of the leases to each partnership covering the acreage on which the wells will be drilled, and pay: o 66% of the equipment costs of drilling and completing the partnership's wells; and o any equipment costs that exceed 10% of the partnership's subscription proceeds which would otherwise be charged to you and the other investors. The managing general partner also will be charged with 100% of the organization and offering costs for each partnership. A portion of these contributions to each partnership will be in the form of payments to itself, its affiliates and third-parties and the remainder will be in the form of services related to organizing this offering. The managing general partner will receive a credit towards its required capital contribution to each partnership for these payments and services as discussed in "Participation in Costs and Revenues." 22 The following tables present information concerning each partnership's use of the proceeds provided by both you and the other investors and the managing general partner. The tables are based on the managing general partner's required capital contribution of at least 25% of all capital contributions for each partnership, which includes its credit for organization and offering costs and contributing the leases. Anthem Securities, an affiliate of the managing general partner, will be the dealer-manager and it will receive the dealer-manager fee, the sales commissions, the .5% accountable reimbursement for permissible non-cash compensation, and the .5% reimbursement for bona fide accountable due diligence expenses. A portion of these payments and reimbursements, including all of the sales commissions and the .5% reimbursement for bona fide accountable due diligence expenses, will be reallowed by the dealer-manager to the broker/dealers, which are referred to as selling agents, as discussed in "Plan of Distribution." Subject to the above, the organizational costs will be paid to the managing general partner, its affiliates and various third-parties, and the intangible drilling costs and tangible costs will be paid to the managing general partner as general drilling contractor and operator under the drilling and operating agreement. The tables are presented based on: o the sale of 200 units, which is the minimum number of units for each partnership; and o the sale of 12,500 units, which is the maximum number of units, in the aggregate, for all partnerships in the program. Substantially all of the proceeds available to each partnership will be expended for the following purposes and in the following manner: INVESTOR CAPITAL
200 12,500 UNITS UNITS NATURE OF PAYMENT SOLD % (1) SOLD % (1) - ----------------- ---- ----- ---- ----- ORGANIZATION AND OFFERING EXPENSES Dealer-manager fee, sales commissions, .5% accountable reimbursement for permissible non-cash compensation, and up to .5% reimbursement for bona fide accountable due diligence expenses........................... $ 0 0% $ 0 0% Organization costs..................................................... - 0 - - 0 - - 0 - - 0 - AMOUNT AVAILABLE FOR INVESTMENT: Intangible drilling costs (2).......................................... $1,800,000 90% $112,500,000 90% Equipment costs (2).................................................... $ 200,000 10% $ 12,500,000 10% Leases................................................................. - 0 - - 0 - - 0 - - 0 - ---------- ----- ------------ ----- TOTAL INVESTOR CAPITAL................................................. $2,000,000 100% $125,000,000 100% ========== ===== ============ =====
- ----------------- (1) The percentage is based on total investor subscription proceeds and excludes the managing general partner's capital contribution. (2) These costs will vary depending on the actual cost of drilling and completing the wells, but not less than 90% of the subscription proceeds provided by you and the other investors will be used to pay intangible drilling costs. Equipment costs will be charged 34% to the investors and 66% to the managing general partner, however the investors' share of these costs may not exceed 10% of the investors' subscription proceeds as discussed in "Participation in Costs and Revenues." Because the actual costs are not known, this table assumes that the maximum 10% of the investors' subscription proceeds is used to pay equipment costs in order to avoid the possibility of overstating the amount of currently deductible intangible drilling costs charged to the investors. In contrast, the managing general partner's share of equipment costs in the "- Managing General Partner Capital" and the "- Total Partnership Capital" tables below is based on the managing general partner's estimate of the average cost of drilling and completing wells in the partnership's primary areas as discussed in "Compensation - Drilling Contracts." In making this estimate, the managing general partner determined that the investors' share of the equipment costs would exceed the 10% limit set forth above if all of the equipment costs were charged 34% to the investors and 66% to the managing general partner. Thus, in the "- Managing General Partner Capital" Table and the "-Total Partnership Capital" Table below, the managing general partner was allocated more than 66% of the total estimated equipment costs and the investors' share of the total estimated equipment costs was limited to 10% of the investors' subscription proceeds. 23 MANAGING GENERAL PARTNER CAPITAL
200 12,500 UNITS UNITS NATURE OF PAYMENT SOLD % (1) SOLD % (1) - ----------------- ---- ----- ---- ----- ORGANIZATION AND OFFERING EXPENSES Dealer-manager fee, sales commissions, .5% accountable reimbursement $210,000 23.67% $13,002,603 24.50% for permissible non-cash compensation, and up to .5% reimbursement for bona fide accountable due diligence expenses (2)....................... Organization costs (2)................................................. $ 90,000 10.14% $ 2,119,403 3.99% AMOUNT AVAILABLE FOR INVESTMENT: Intangible drilling costs.............................................. - 0 - - 0 - - 0 - 0% Equipment costs (3).................................................... $535,000 60.29% $34,166,354 64.39% Leases (4)............................................................. $ 52,320 5.90% $ 3,777,504 7.12% -------- ----- ----------- ----- TOTAL MANAGING GENERAL PARTNER CAPITAL................................. $887,320 100% $53,065,864 100% ======== ===== =========== =====
- ------------------ (1) The percentage is based on the managing general partner's capital contribution and excludes the investors' subscription proceeds. (2) As discussed in "Participation in Costs and Revenues," if these fees, sales commissions, reimbursements and organization costs exceed 15% of the investors' subscription proceeds in a partnership, then the excess will be charged to the managing general partner, but will not be included as part of its capital contribution. (3) The managing general partner's share of equipment costs is described in "Compensation - Drilling Contracts." However, these costs will vary depending on the actual costs of drilling and completing the wells. Also, see footnote (2) to the "- Investor Capital" table above. (4) Instead of contributing cash for the leases, the managing general partner will assign to each partnership the leases covering the acreage on which the partnership's wells will be drilled. Generally, as described in "Compensation - Lease Costs," the managing general partner's lease cost is approximately $5,232 per prospect and for purposes of this table the managing general partner's lease costs have been quantified using this amount based on its estimate of the number of net wells that will be drilled. However, the managing general partner's lease costs on a prospect may be significantly higher than the above-referenced amount, and its credit for the leases contributed will equal its cost, unless it has a reason to believe that cost is materially more than fair market value of the property, in which case its credit for its lease contribution must not exceed fair market value. TOTAL PARTNERSHIP CAPITAL
200 12,500 UNITS UNITS NATURE OF PAYMENT SOLD % (1) SOLD % (1) - ----------------- ---- ----- ---- ----- ORGANIZATION AND OFFERING EXPENSES Dealer-manager fee, sales commissions, .5% accountable reimbursement $ 210,000 7.27% $ 13,002,603 7.30% for permissible non-cash compensation, and up to .5% reimbursement for bona fide accountable due diligence expenses (2)....................... Organization costs (2)................................................. $ 90,000 3.12% $ 2,119,403 1.19% AMOUNT AVAILABLE FOR INVESTMENT: Intangible drilling costs (3).......................................... $1,800,000 62.34% $112,500,000 63.18% Equipment costs (3).................................................... $ 735,000 25.46% $ 46,666,354 26.21% Leases (4)............................................................. $ 52,320 1.81% $ 3,777,504 2.12% ---------- ----- ------------ ----- TOTAL PARTNERSHIP CAPITAL.............................................. $2,887,320 100% $178,065,864 100% ========== ===== ============ =====
24 - ---------------- (1) The percentage is based on total investor subscription proceeds and the managing general partner's estimate of its capital contributions. (2) As discussed in "Participation in Costs and Revenues," if these fees, sales commissions, reimbursements and organization costs exceed 15% of the investors' subscription proceeds in a partnership, then the excess will be charged to the managing general partner, but will not be included as part of its capital contribution. (3) The managing general partner's share of equipment costs is described in "Compensation - Drilling Contracts." However, these costs will vary depending on the actual cost of drilling and completing the wells, but not less than 90% of the subscription proceeds provided by you and the other investors will be used to pay intangible drilling costs. Also, see footnote (2) to the "- Investor Capital" table, above. (4) Instead of contributing cash for the leases, the managing general partner will assign to each partnership the leases covering the acreage on which the partnership's wells will be drilled. Generally, as described in "Compensation - Lease Costs," the managing general partner's lease cost is approximately $5,232 per prospect and for purposes of this table the managing general partner's lease costs have been quantified using this amount based on its estimate of the number of net wells that will be drilled. However, the managing general partner's lease costs on a prospect may be significantly higher than the above-referenced amount, and its credit for the leases contributed will equal its cost, unless it has a reason to believe that cost is materially more than fair market value of the property, in which case its credit for its lease contribution must not exceed fair market value. COMPENSATION The items of compensation to be paid to the managing general partner and its affiliates from each partnership are set forth below. Most of these items of compensation depend on how many wells a partnership drills and how much of the working interest in each of the wells is owned by the partnership. In this regard, the managing general partner estimates that approximately 10 gross and net wells will be drilled if the minimum required subscription proceeds of $2 million are received by a partnership, and approximately 761 gross wells, which will be 722 net wells, will be drilled, in the aggregate, if subscription proceeds of $125 million are received by the partnerships. A gross well is a well in which a partnership owns a working interest. This is compared with a net well which is the sum of the fractional working interests owned in the gross wells. For example, a 50% working interest owned in three wells is three gross wells, but 1.5 net wells. However, the managing general partner's estimate set forth above of the number of wells to be drilled is subject to risks which can cause actual results to vary. (See "Risk Factors - Risks Related to an Investment in a Partnership - The Partnerships Do Not Own Any Prospects, the Managing General Partner Has Complete Discretion to Select Which Prospects are Acquired By a Partnership, and The Possible Lack of Information for a Majority of the Prospects Decreases Your Ability to Evaluate the Feasibility of a Partnership.") NATURAL GAS AND OIL REVENUES Subject to the managing general partner's subordination obligation, the investors and the managing general partner will share in each partnership's revenues in the same percentages as their respective capital contributions bear to the total partnership capital contributions for that partnership except that the managing general partner will receive an additional 7% of that partnership's revenues. However, the managing general partner's total revenue share may not exceed 35% of that partnership's revenues regardless of the amount of its capital contribution. For example, if the managing general partner contributes the minimum of 25% of the total partnership capital contributions and the investors contribute 75% of the total partnership capital contributions, then the managing general partner will receive 32% of the partnership revenues and the investors will receive 68% of the partnership revenues. On the other hand, if the managing general partner contributes 30% of the total partnership capital contributions and the investors contribute 70% of the total partnership capital contributions, then the managing general partner will receive 35% of the partnership revenues, not 37%, because its revenue share cannot exceed 35% of partnership revenues, and the investors will receive 65% of partnership revenues. As noted above, the managing general partner's revenue share from each partnership is subject to its subordination obligation as described in "Participation in Costs and Revenues - Subordination of Portion of the Managing General Partner's Net Revenue Share" and the accompanying tables. For example, if the managing general partner's revenue share is 35% of the partnership revenues, then up to 17.5% of the managing general partner's partnership net revenues could be used for its subordination obligation. 25 LEASE COSTS Under the partnership agreement the managing general partner will contribute to each partnership all the undeveloped leases necessary to cover each of the partnership's prospects. The managing general partner will receive a credit to its capital account equal to: o the cost of the leases; or o the fair market value of the leases if the managing general partner has reason to believe that cost is materially more than the fair market value. The cost of the leases will include a portion of the managing general partner's reasonable, necessary, and actual expenses for services allocated to a partnership's leases by it using industry guidelines. In the primary areas of interest, the managing general partner's lease cost is approximately $5,232 per prospect assuming a partnership acquires 100% of the working interest in the prospect, although from time to time the managing general partner's lease costs on a prospect may be significantly higher than this amount. The managing general partner's credit for lease costs will be proportionally reduced to the extent a partnership acquires less than 100% of the working interest in the prospect. In this regard, a working interest generally means an interest in the lease under which the owner of the working interest must pay some portion of the cost of development, operation, or maintenance of the well. Assuming all the leases are situated in these areas, the managing general partner estimates that its credit for lease costs will be: o $52,320 if $2 million is received, which is 10 net wells times $5,232 per prospect; and o $3,777,504 if $125 million is received, which is 722 net wells times $5,232 per prospect. Drilling a partnership's wells may also provide the managing general partner with offset prospects to be drilled 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 Each partnership will enter into the drilling and operating agreement with the managing general partner to drill and complete each partnership's wells at cost plus 15%. The managing general partner has determined that this is a competitive rate based on: o information it has concerning drilling rates of third-party drilling companies in the Appalachian Basin; o the estimated costs of non-affiliated persons to drill and equip wells in the Appalachian Basin as reported for 2002 by an independent industry association which surveyed other non-affiliated operators in the area; and o information it has concerning increases in drilling costs in the area since 2002. If this rate subsequently 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. However, the 15% premium may not be increased by the managing general partner during the term of the partnership. The managing general partner expects to subcontract some of the actual drilling and completion of each 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, and may not profit by drilling in contravention of its fiduciary obligations to the partnership. 26 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 reimbursement to the managing general partner of its general and administrative overhead as discussed below. This amount will be proportionately reduced to the extent a partnership acquires less than 100% of the working interest in the prospect. The cost of the well also includes all ordinary costs of drilling, testing and completing the well. This includes the cost of the following for a natural gas well, which will be the classification of the majority of the wells: o multiple completions, which means, in general, treating separately all potentially productive geological formations in an attempt to enhance the gas production from the well; o installing gathering lines for the natural gas of up to 2,500 feet; and o the necessary facilities for the production of natural gas. The amount of compensation that the managing general partner could earn as a result of these arrangements depends on many factors, including where the wells are drilled and their depths, the method used to complete the well, and the number of wells drilled. Assuming the maximum subscription proceeds of $125 million, the managing general partner anticipates that the partnerships' weighted average cost of drilling and completing approximately 722 net wells, excluding lease costs, will be approximately $220,260, which includes reimbursement to the managing general partner of the investors' share of its general and administrative overhead of approximately $12,722, as described below. This estimate was based on: o the number of wells that the managing general partner estimates will be drilled in each area; o the percentage of working interest that the managing general partner anticipates the partnerships will acquire in the prospects in each area; and o the associated estimated drilling and completion costs, which are different for each area based primarily on different depths and completion methods. Thus, the managing general partner's estimated weighted average cost of drilling and completing one net well as set forth above, in all likelihood, will vary from the actual average cost of the wells in each of the primary areas. Based on the assumptions and the estimated weighted average cost for one net well as set forth above, the managing general partner expects that its 15% profit will be approximately $22,558 with respect to the intangible drilling costs and the portion of equipment costs paid by you and the other investors. In making this estimate, the managing general partner further assumed that the investors' 34% share of the equipment costs would be reduced so that it would not exceed the limit of 10% of investor subscription proceeds as discussed in footnote (2) to the "- Investor Capital" table in "Capitalization and Source of Funds and Use of Proceeds." For this reason and because the managing general partner anticipates that the partnerships will not acquire 100% of the working interest in all of their respective prospects, the managing general partner estimates that the investors' share of its reimbursement for general and administrative overhead will be a weighted average of approximately $12,722 for one net well, rather than the maximum of $12,781 per well assuming a 34% share of the equipment costs and a 100% working interest in the well. The actual compensation received by the managing general partner as a result of each partnership's drilling operations will vary from these estimates, but the managing general partner's profit will not in any event exceed 15% of the costs of drilling and completing the wells. Also, to the extent that a partnership acquires less than a 100% working interest in a well, its drilling and completion costs of that well will be proportionately decreased. Subject to the foregoing, the managing general partner estimates that its general and administrative overhead reimbursement of $12,722 and profit of 15% (approximately $22,558) for one net well, which totals $35,280, will be: o $352,800 if $2 million is received, which is 10 net wells times $35,280; and o $25,472,160 if $125 million is received, which is 722 net wells times $35,280. 27 The managing general partner's estimated weighted average cost of $220,260 for one net well as discussed above consists of: o intangible drilling costs of approximately $155,790 (70.7%); and o equipment costs of approximately $64,470 (29.3%). In this regard, the managing general partner further anticipates that a partnership's cost of drilling and completing any given well in the partnerships' primary areas as described in "Proposed Activities," excluding lease costs, may range from as low as approximately $120,000 to as high as $285,000 or more, depending on the area. PER WELL CHARGES Under the drilling and operating agreement the managing general partner, as operator of the wells, will receive the following from each partnership when the wells begin producing: o reimbursement at actual cost for all direct expenses incurred on behalf of the partnership; and o well supervision fees for operating and maintaining the wells during producing operations at a competitive rate. Currently the competitive rate for well supervision fees is $285 per well per month in the primary and secondary areas. The well supervision fees will be proportionately reduced to the extent the partnership acquires less than 100% of the working interest in the well, and may be adjusted for inflation annually beginning with the second calendar year after a partnership closes. If in the future the foregoing rate exceeds competitive rates available from other non-affiliated persons in the area engaged in the business of providing comparable services or equipment, then the rate 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 received for operator services be duplicative of any consideration or reimbursement received under the partnership agreement. The well supervision fees cover all normal and regularly recurring operating expenses for the production, delivery, and sale of natural gas and oil, such as: o well tending, routine maintenance, and adjustment; o reading meters, recording production, pumping, maintaining appropriate books and records; and o preparing reports to the partnership and government agencies. The well supervision fees do not include costs and expenses related to: o the purchase of equipment, materials, or third-party services; o brine disposal; and o rebuilding of access roads. These costs will be charged at the invoice cost of the materials purchased or the third-party services performed. The managing general partner estimates that it will receive well supervision fees for a partnership's first 12 months of operation after all of the wells have been placed in production of: o $34,200 if $2 million is received, which is 10 net wells at $285 per well per month; and o $2,469,240 if $125 million is received, which is 722 net wells at $285 per well per month. 28 GATHERING FEES Under the partnership agreement the managing general partner will be responsible for gathering and transporting the natural gas produced by the partnerships to interstate pipeline systems, local distribution companies, and/or end-users in the area. The managing general partner anticipates that it will use the gathering system owned by Atlas Pipeline Partners for the majority of the natural gas as described in "Proposed Activities - Sale of Natural Gas and Oil Production - Gathering of Natural Gas." The managing general partner's affiliate, Atlas America, Inc., which is sometimes referred to in this prospectus as "Atlas America," or another affiliate controls and manages the pipeline for Atlas Pipeline Partners. Also, Atlas America and the managing general partner's affiliates, Resource Energy, Inc., sometimes referred to in this prospectus as "Resource Energy," and Viking Resources Corporation, sometimes referred to in this prospectus as "Viking Resources," (the "Resource Entities"), which do not include the partnerships, have an agreement with Atlas Pipeline Partners which provides that generally all of the gas produced by their affiliated partnerships, which includes each partnership composing the program, will be gathered and transported through Atlas Pipeline Partners and that the Resource Entities must pay the greater of $.35 per mcf or 16% of the gross sales price for each mcf transported by these affiliated partnerships. Each partnership will pay a gathering fee directly to the managing general partner at competitive rates. If the gathering system owned by Atlas Pipeline Partners is used by the partnership, the managing general partner will apply the gathering fee it receives towards the payments owed by the Resource Entities under their agreement with Atlas Pipeline Partners. If a third-party gathering system is used, the managing general partner will pay a portion or all of its gathering fee to the third-party gathering the natural gas. The current rates for gathering fees, which have been determined by the managing general partner for each partnership's primary and secondary drilling areas, are set forth in the chart below. Although the gathering fee paid by each partnership to the managing general partner may be increased by the managing general partner, in its sole discretion, from those set forth in the chart below, the managing general partner may not increase the gathering fees beyond those charged by unaffiliated third-parties in the same geographic area engaged in similar businesses. The gathering fees have not been increased by the managing general partner in several years.
CURRENT AMOUNT OF GATHERING FEES TO EACH PARTNERSHIP'S PRIMARY AND BE PAID BY EACH PARTNERSHIP TO SECONDARY DRILLING AREAS MANAGING GENERAL PARTNER (1) - ------------------------ ---------------------------- Clinton/Medina Geological Formation in Western Pennsylvania in Crawford, Mercer, Lawrence, Warren, and Venango Counties, and Eastern Ohio primarily in Stark, Mahoning, Trumbull and Portage Counties ......................................................................$.29 per mcf Mississippian/Upper Devonian Sandstone Reservoirs in Fayette and Greene Counties, Pennsylvania..............................................$.35 per mcf Upper Devonian Sandstone Reservoirs in Armstrong County, Pennsylvania..................................................................(2) Upper Devonian Sandstone Reservoirs in McKean County, Pennsylvania........................................................$.70 per mcf (3) Clinton/Medina Geological Formation in New York............................................$.35 per mcf Clinton/Medina Geological Formation in Southern Ohio.......................................$.35 per mcf
- -------------- (1) The gathering fee paid by each partnership must not exceed a competitive rate as determined by the managing general partner, and the managing general partner may increase or decrease the gathering fee to a competitive rate from time to time if conditions in the industry change. (2) Each partnership will use a gathering system provided by a third-party joint venture partner which will not charge the partnership a gathering fee if it markets the gas. If the managing general partner markets the gas for the partnership, then the partnership will pay a gathering fee to the managing general partner equal to that charged by the third-party, which the managing general partner anticipates will be $.20 per mcf. (3) In this area, a partnership will deliver gas into a gathering system a segment of which will be provided by Atlas Pipeline Partners and a segment of which will be provided by a third-party. The third-party will receive fees of $.25 per mcf for transportation and $.10 per mcf for compression. From the gathering fees charged the partnership by the managing general partner, the managing general partner will pay $.35 per mcf to the third-party and $.35 per mcf to Atlas Pipeline Partners. 29 The actual amount of gathering fees to be paid by a partnership to the managing general partner cannot be quantified because the volume of natural gas that will be produced and transported from the partnership's wells cannot be predicted. DEALER-MANAGER FEES Subject to certain exceptions described in "Plan of Distribution," Anthem Securities, the dealer-manager and an affiliate of the managing general partner, will receive on each unit sold to an investor: o a 2.5% dealer-manager fee; o a 7% sales commission; o a .5% reimbursement for accountable permissible non-cash compensation; and o an up to .5% reimbursement of the selling agents' bona fide accountable due diligence expenses. Assuming the above amounts are paid for all units sold, the dealer-manager will receive: o $210,000 if $2 million is received by a partnership; and o $13,125,000 if $125 million is received by the partnerships. All of the reimbursement of the selling agents' bona fide accountable due diligence expenses, and generally all of the accountable permissible non-cash compensation reimbursement and sales commissions, will be reallowed to the selling agents. Most of the 2.5% dealer-manager fee will be reallowed to the wholesalers who are associated with the managing general partner and registered through Anthem Securities for subscriptions obtained through their efforts. The dealer-manager will retain any of the compensation which is not reallowed. See "Management" for the ownership of Anthem Securities. INTEREST AND OTHER COMPENSATION The managing general partner or an affiliate will have the right to charge a competitive rate of interest on any loan it may make to or on behalf of a partnership. If the managing general partner provides equipment, supplies, and other services to a partnership, then it may do so at competitive industry rates. The managing general partner will determine a competitive rate of interest and competitive industry rates for equipment, supplies and other services by conducting a survey of the interest and/or fees charged by unaffiliated third-parties in the same geographic area engaged in similar businesses. If possible, the managing general partner will contact at least two unaffiliated third-parties, however, the managing general partner will have sole discretion in determining the amount to be charged a partnership. ESTIMATE OF ADMINISTRATIVE COSTS AND DIRECT COSTS TO BE BORNE BY THE PARTNERSHIPS The managing general partner and its affiliates will receive from each partnership 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 payment per well is subject to the following: o it will not be increased in amount during the term of the partnership; o it will be proportionately reduced to the extent the partnership acquires less than 100% of the working interest in the well; o it will be the entire payment to reimburse the managing general partner for the partnership's administrative costs; and 30 o it will not be received for plugged or abandoned wells. The managing general partner estimates that the unaccountable, fixed payment reimbursement for administrative costs allocable to a partnership's first 12 months of operation after all of its wells have been placed into production will not exceed approximately: o $9,000 if $2 million is received, which is 10 net wells at $75 per well per month; and o $649,800 if $125 million is received, which is 722 net wells at $75 per well per month. Direct costs will be determined by the managing general partner, in its sole discretion, including the provider of the services or goods and the amount of the provider's compensation. Direct costs will be billed directly to and paid by each partnership to the extent practicable. The anticipated direct costs set forth below for a partnership's first 12 months of operation after all of its wells have been placed into production may vary from the estimates shown for numerous reasons which cannot accurately be predicted. These reasons include: o the number of investors; o the number of wells drilled; o the partnership's degree of success in its activities; o the extent of any production problems; o inflation; and o various other factors involving the administration of the partnership.
Minimum Maximum Subscriptions Subscriptions of $2 million of $125 million (1) ------------- ------------------- DIRECT COSTS External Legal.................................................... $ 6,000 $ 18,000 Accounting Fees for Audit and Tax Preparation..................... 42,000 126,000 Independent Engineering Reports................................... 1,500 40,000 ------- -------- TOTAL ............................................................ $49,500 $184,000 ======= ========
- --------- (1) This assumes three partnerships are formed as described below in "Terms of the Offering - Subscription to a Partnership" and the targeted nonbinding subscriptions of each partnership are received. TERMS OF THE OFFERING SUBSCRIPTION TO A PARTNERSHIP Atlas America Public #14-2004 Program will offer for sale an aggregate of $125 million of units in a series of up to three limited partnerships to be formed under the Delaware Revised Uniform Limited Partnership Act. You may purchase units only if you meet the suitability standards set forth below. The units will be offered for sale over a period which may extend from the date of this prospectus up to December 31, 2005, but may end earlier. The minimum required aggregate subscription proceeds for the offering of units in each partnership will be $2 million after the discounts described in "Plan of Distribution" and excluding any subscriptions by the managing general partner or its affiliates. If this minimum amount of aggregate subscriptions is not received in the offering of units of any partnership by its offering termination date, then the partnership will not be funded, and the escrow agent will promptly return all subscription proceeds for that partnership to the respective subscribers in full with any interest earned on the escrowed funds and without deduction for any fees from the escrowed funds. 31 Set forth below are the targeted subscriptions for each partnership, although these targeted amounts are not mandatory and the managing general partner may determine the subscription amount for each partnership in its sole discretion. The maximum subscription of any partnership must be the lesser of: o the registered amount of $125 million; or o the number of units remaining unsold in any prior partnership from the $125 million aggregate registration. Also, the targeted ending dates for each partnership, which are not binding on the partnerships except that the units in each partnership may not be offered beyond that partnership's offering termination date, are set forth below. Otherwise the managing general partner may close the offering of units in a partnership before its targeted ending date or withdraw the offering of units in the partnership at any time.
REQUIRED TARGETED TARGETED OFFERING PARTNERSHIP MINIMUM SUBSCRIPTION ENDING TERMINATION NAME SUBSCRIPTION PROCEEDS (2) DATE (1)(2) DATE (2) ----------- ------------ ------------ ----------- ----------- Atlas America Public #14-2004 $2 million $50 million 12/31/04 12/31/04
o The units in the above partnership will be sold only during 2004.
Atlas America Public #14-2005(A) $2 million $35 million 05/31/05 05/31/05 Atlas America Public #14-2005(B) $2 million $40 million 08/31/05 12/31/05
o The units in the above partnerships will be sold only during 2005. - ------------ (1) The partnerships will conduct the offering of their respective units in a series. Thus, the offering of units in the partnerships designated Atlas America Public #14-2005(___) L.P. will not begin until the subscriptions for units in the prior partnership, if any, have reached the minimum subscriptions or that prior offering has ended. (2) The managing general partner may close the subscription period of any partnership at any time once the partnership is in receipt of the minimum required subscription proceeds. Units are offered at a subscription price of $10,000 per unit, subject to certain exceptions which are described in "Plan of Distribution," and must be paid 100% in cash at the time of subscribing. The subscription price of the units has been arbitrarily determined by the managing general partner because the partnerships do not have any prior operations, assets, earnings, liabilities or present value. 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 in each partnership. Larger fractional subscriptions will be accepted in $1,000 increments, beginning with either $11,000, $12,000, etc. if you pay $10,000 for a full unit or $6,000, $7,000, etc. if you pay $5,000 for a one-half unit. You will have the election to purchase units in a partnership as either an investor general partner or a limited partner. However, the managing general partner will have exclusive management authority for each partnership. Each partnership will be a separate business entity from the other partnerships. Thus, as an investor, you will be a partner only in the partnership in which you invest. You will have no interest in the business, assets or tax benefits of the other partnerships unless you also invest in the other partnerships. Your investment return will depend solely on the operations and success or lack of success of the particular partnership in which you invest. 32 PARTNERSHIP CLOSINGS AND ESCROW Subscription proceeds for each partnership will be held in a separate interest bearing escrow account at National City Bank of Pennsylvania until receipt of the minimum subscription proceeds. A partnership may not break escrow unless the partnership is in receipt of subscription proceeds of $2 million after the discounts described in "Plan of Distribution" and excluding any subscriptions by the managing general partner or its affiliates. However, on receipt of the minimum subscription proceeds and written instructions to the escrow agent from the managing general partner and the dealer-manager, the managing general partner on behalf of a partnership may: o break escrow; and o transfer the escrowed funds to a partnership account and begin drilling operations as set forth in "- Activation of the Partnerships," below. At or about the time of the initial closing of a particular partnership, the managing general partner anticipates it will supplement this prospectus to reflect the results of the initial closing of that partnership. If the minimum subscription proceeds are not received by the offering termination date of a partnership, then the sums deposited in the escrow account will be promptly returned to you and the other subscribers in that partnership with interest and without deduction for any fees. In this regard, the latest offering termination date is December 31, 2004, for Atlas America Public #14-2004 L.P., May 31, 2005 for Atlas America Public #14-2005(A) L.P., and December 31, 2005, for Atlas America Public #14-2005(B) L.P. Although the managing general partner and its affiliates may buy up to 5% 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 subscription proceeds required for a partnership to break escrow and begin operations. You will receive interest on your subscription proceeds from the time they are deposited in the escrow account, or the partnership account if you subscribe after the minimum subscription proceeds have been received and escrow has been broken, until the final closing of the partnership to which you subscribed. The interest will be paid to you not later than your partnership's first cash distribution from operations. During each partnership's escrow period its subscription proceeds will be invested only in institutional investments comprised of or secured by securities of the United States government. After the funds are transferred to the partnership account and before their use in partnership operations, they may be temporarily invested in income producing short-term, highly liquid investments, in which there is appropriate safety of principal, such as U.S. Treasury Bills. If the managing general partner determines that a partnership may be deemed an investment company under the Investment Company Act of 1940, then the investment activity will cease. Subscription proceeds will not be commingled with the funds of the managing general partner or its affiliates, nor will subscription proceeds be subject to their creditors' claims before they are paid to the managing general partner under the drilling and operating agreement. ACCEPTANCE OF SUBSCRIPTIONS You and the other investors should make your checks for units payable to "Atlas America Public #14-2004 L.P., Escrow Agent, National City Bank of PA," or "Atlas America Public #14-2005(___) L.P., Escrow Agent, National City Bank of PA," as appropriate, and give your check to your broker/dealer for submission to the dealer-manager and escrow agent. The managing general partner will place all subscription proceeds of each partnership in an escrow account, or the partnership account if you subscribe after the minimum subscription proceeds have been received and escrow has been broken, until the final closing of the partnership to which you subscribed. Your execution of the subscription agreement constitutes your offer to buy units in the partnership then being offered and to hold the offer open until either: o your subscription is accepted or rejected by the managing general partner; or o you withdraw your offer. To withdraw your offer, you must give written notice to the managing general partner before your offer is accepted by the managing general partner. Your subscription will be accepted or rejected by the partnership within 30 days of its receipt. The managing general partner's acceptance of your subscription is discretionary, and the managing general partner may reject your subscription for any reason without incurring any liability to you for this decision. If your subscription is rejected, then all of your funds will be promptly returned to you together with any interest earned on your subscription proceeds. 33 When you will be admitted to a partnership depends on whether your subscription is accepted before or after breaking escrow. If your subscription is accepted: o before breaking escrow, then you will be admitted to the partnership to which you subscribed not later than 15 days after the release from escrow of the investors' funds to that partnership; and o after breaking escrow, then you will be admitted to the partnership to which you subscribed not later than the last day of the calendar month in which your subscription was accepted by that partnership. Your execution of the subscription agreement and the managing general partner's acceptance also constitutes your: o execution of the partnership agreement and agreement to be bound by its terms as a partner; and o grant of a special power of attorney to the managing general partner to file amended certificates of limited partnership and governmental reports, and perform certain other actions on behalf of you and the other investors. ACTIVATION OF THE PARTNERSHIPS The managing general partner will organize each partnership under the Delaware Revised Uniform Limited Partnership Act before the initial closing of the partnership and breaking escrow. In this regard, the first partnership in the program, Atlas America Public #14-2004 L.P., has been formed as a Delaware limited partnership. (See "Financial Information Concerning the Managing General Partner and Atlas America Public #14-2004 L.P.") However, the other partnerships have not yet been formed. The units offered in those partnerships in 2005 may be preformation investor general partner interests and preformation limited partner interests which will become units of investor general partner interests or limited partner interests, respectively, in the particular partnership if it has not been formed at the time you subscribe. After the initial closing of a partnership and the transfer of the escrowed funds to a partnership account, the managing general partner on behalf of a partnership may: o enter into the drilling and operating agreement with itself or an affiliate as operator; and o begin drilling to the extent the prospects have been identified in this prospectus or by a supplement or an amendment to the registration statement of which this prospectus is a part. SUITABILITY STANDARDS IN GENERAL. It is the obligation of persons selling the units to make every reasonable effort to assure that the units are suitable for you based on your investment objectives and financial situation, regardless of your income or net worth. However, you should invest in a partnership only if you are willing to assume the risk of a speculative, illiquid, and long-term investment. Also, subscriptions to a partnership will not be accepted from IRAs, Keogh plans and qualified retirement plans because the partnership's income would be characterized as unrelated business taxable income, which is subject to federal income tax. The decision to accept or reject your subscription will be made by the managing general partner, in its sole discretion, and is final. The managing general partner will not accept your subscription until it has reviewed your apparent qualifications, and the suitability determination must be maintained by the managing general partner during the partnership's term and for at least six years thereafter. GENERAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF LIMITED PARTNER UNITS. If you are a resident of any of the following states or jurisdictions: 34
o ALABAMA, o KANSAS, o NORTH DAKOTA, o ALASKA, o KENTUCKY, o OKLAHOMA, o ARIZONA, o LOUISIANA, o OREGON, o ARKANSAS, o MAINE, o RHODE ISLAND, o COLORADO, o MARYLAND, o SOUTH CAROLINA, o CONNECTICUT, o MASSACHUSETTS, o SOUTH DAKOTA, o DELAWARE, o MINNESOTA, o TENNESSEE, o DISTRICT OF COLUMBIA, o MISSISSIPPI, o TEXAS, o FLORIDA, o MISSOURI, o UTAH, o GEORGIA, o MONTANA, o VERMONT, o HAWAII, o NEBRASKA, o VIRGINIA, o IDAHO, o NEVADA, o WASHINGTON, o ILLINOIS, o NEW JERSEY, o WEST VIRGINIA, o INDIANA, o NEW MEXICO, o WISCONSIN, AND o IOWA, o NEW YORK, o WYOMING,
then units will be sold to you if you meet either of the following requirements: o a minimum net worth of $225,000, exclusive of home, home furnishings, and automobiles; or o a minimum net worth of $60,000, exclusive of home, home furnishings, and automobiles, 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. However, if you are a resident of the states set forth below, then additional suitability requirements apply to you. SPECIAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF LIMITED PARTNER UNITS IN CALIFORNIA, MICHIGAN, NEW HAMPSHIRE, NORTH CAROLINA, OHIO AND PENNSYLVANIA. o If you are a resident of CALIFORNIA and you purchase limited partner units, then you must meet any one of the following special suitability requirements: o a net worth of not less than $250,000, exclusive of home, home furnishings, and automobiles, and expect to have gross income in the current tax year of $65,000 or more; or o a net worth of not less than $500,000, exclusive of home, home furnishings, and automobiles; or o a net worth of not less than $1 million; or o expected gross income in the current tax year of not less than $200,000. o If you are a resident of MICHIGAN or NORTH CAROLINA and you purchase limited partner units, then you must meet either of the following special suitability requirements: o a net worth of not less than $225,000, exclusive of home, home furnishings, and automobiles; or 35 o a net worth of not less than $60,000, exclusive of home, 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. o If you are a resident of NEW HAMPSHIRE and you purchase limited partner units, then you must meet either of the following special suitability requirements: o a net worth of not less than $250,000, exclusive of home, home furnishings, and automobiles; or o a net worth of not less than $125,000, exclusive of home, home furnishings, and automobiles and $50,000 of taxable income. o In addition, if you are a resident of MICHIGAN, OHIO, or PENNSYLVANIA, then you must not make an investment in a partnership which is in excess of 10% of your net worth, exclusive of home, home furnishings and automobiles. GENERAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF INVESTOR GENERAL PARTNER UNITS. If you are a resident of any of the following states or jurisdictions:
o ALASKA, o ILLINOIS, o RHODE ISLAND, o COLORADO, o LOUISIANA, o SOUTH CAROLINA, o CONNECTICUT, o MARYLAND, o UTAH, o DELAWARE, o MONTANA, o VIRGINIA, o DISTRICT OF COLUMBIA, o NEBRASKA, o WEST VIRGINIA, o FLORIDA, o NEVADA, o WISCONSIN, AND o GEORGIA, o NEW JERSEY, o WYOMING, o HAWAII, o NEW YORK, o IDAHO, o NORTH DAKOTA,
then units will be sold to you if you meet either of the following requirements: o a minimum net worth of $225,000, exclusive of home, home furnishings, and automobiles; or o a minimum net worth of $60,000, exclusive of home, home furnishings, and automobiles, 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. However, if you are a resident of the states set forth below, then additional suitability requirements apply to you. SPECIAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF INVESTOR GENERAL PARTNER UNITS IN EITHER: (I) ALABAMA, ARKANSAS, MAINE, MASSACHUSETTS, MINNESOTA, NORTH CAROLINA, OHIO, OKLAHOMA, PENNSYLVANIA, TENNESSEE, TEXAS, OR WASHINGTON; OR (II) ARIZONA, INDIANA, IOWA, KANSAS, KENTUCKY, MICHIGAN, MISSISSIPPI, MISSOURI, NEW MEXICO, OREGON, SOUTH DAKOTA, OR VERMONT. o If you are a resident of any of the following states: 36
o ALABAMA, o MINNESOTA, o PENNSYLVANIA, o ARKANSAS, o NORTH CAROLINA, o TENNESSEE, o MAINE, o OHIO, o TEXAS, OR o MASSACHUSETTS, o OKLAHOMA, o WASHINGTON
and you purchase investor general partner units, then you must meet any one of the following special suitability requirements: o 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 o an individual or joint net worth with your spouse in excess of $1 million, inclusive of home, home furnishings, and automobiles; or o an individual or joint net worth with your spouse in excess of $500,000, exclusive of home, home furnishings, and automobiles; or o 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. o In addition, if you are a resident of OHIO or PENNSYLVANIA, then you must not make an investment in a partnership which is in excess of 10% of your net worth, exclusive of home, home furnishings, and automobiles. o If you are a resident of any of the following states:
o ARIZONA, o KENTUCKY, o NEW MEXICO, o INDIANA, o MICHIGAN, o OREGON, o IOWA, o MISSISSIPPI, o SOUTH DAKOTA, OR o KANSAS, o MISSOURI, o VERMONT
and you purchase investor general partner units, then you must meet any one of the following special suitability requirements: o 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 o an individual or joint net worth with your spouse in excess of $1 million, inclusive of home, home furnishings, and automobiles; or o an individual or joint net worth with your spouse in excess of $500,000, exclusive of home, home furnishings, and automobiles; or o 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. 37 o In addition, if you are a resident of IOWA OR MICHIGAN, then you must not make an investment in a partnership which is in excess of 10% of your net worth, exclusive of home, home furnishings, and automobiles. SPECIAL SUITABILITY REQUIREMENTS FOR PURCHASERS OF INVESTOR GENERAL PARTNER UNITS IN EITHER CALIFORNIA OR NEW HAMPSHIRE. o If you are a resident of CALIFORNIA and you purchase investor general partner units, then you must meet any one of the following special suitability requirements: o a net worth of not less than $250,000, exclusive of home, home furnishings, and automobiles, and expect to have gross income in the current tax year of $120,000 or more; or o a net worth of not less than $500,000, exclusive of home, home furnishings, and automobiles; or o a net worth of not less than $1 million; or o expected gross income in the current tax year of not less than $200,000. o If you are a resident of NEW HAMPSHIRE and you purchase investor general partner units, then you must meet either of the following special suitability requirements: o a net worth of not less than $250,000, exclusive of home, home furnishings, and automobiles, of $250,000; or o a net worth of not less than $125,000, exclusive of home, home furnishings, and automobiles, of $125,000 and $50,000 of taxable income. FIDUCIARY ACCOUNTS AND CONFIRMATIONS. If there is a sale of a unit to a fiduciary account, then all the suitability standards set forth above must be met by: o the beneficiary; o the fiduciary account; or o the donor or grantor who directly or indirectly supplies the funds to purchase the units if the donor or grantor is the fiduciary. Generally, you are required to execute your own subscription agreement, and the managing general partner will not accept any subscription agreement that has been executed by someone other than you. The only exception is if you have given someone else the legal power of attorney to sign on your behalf and you meet all of the conditions in this prospectus. Also, the managing general partner will: o not complete a sale of units to you until at least five business days after the date you receive a final prospectus; and o send you a confirmation of purchase. 38 PRIOR ACTIVITIES The following tables reflect certain historical data with respect to 34 private drilling partnerships which raised a total of $195,300,802, and 12 public drilling partnerships which raised a total of $167,610,898, that the managing general partner has sponsored. The tables also reflect certain historical data with respect to 1999 Viking Resources LP, a private drilling program which raised $4,555,210, and is the only drilling program sponsored by Viking Resources after it was acquired by Resource America, Inc. in August 1999. Information concerning other programs sponsored by Viking Resources before it was acquired by Resource America will be provided to you on written request to the managing general partner. The tables do not include information concerning Atlas America Series 25-2004(A) L.P., a private drilling partnership which raised $26,366,052.50, because that program only recently began its drilling phase. Additional information concerning this program will be provided on written request to the managing general partner. The tables also do not include information concerning wells acquired by Atlas Resources through merger or other form of acquisition and this information also will be available on written request. Although past performance is no guarantee of future results, the investor general partners in the managing general partner's prior partnerships have not had to make additional capital contributions to their partnerships because of their status as investor general partners. 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: o PARTNERSHIP TERMS; o PROPERTY LOCATIONS; o PARTNERSHIP SIZE; AND o 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. 39 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 APRIL 15, 2004
Managing Years Number General Date Date of Wells Previous of Investor Partner Total Operations First In Assess- Partnership Investors Capital Capital Capital Began Distributions Production ments ----------- --------- ------- ------- ------- ----- ------------- ---------- ----- 1. Atlas L.P. #1 - 1985 19 $600,000 $114,800 $714,800 12/31/85 07/02/86 18.30 -0- 2. A.E. Partners 1986 24 631,250 120,400 751,650 12/31/86 04/02/87 17.30 -0- 3. A.E. Partners 1987 17 721,000 158,269 879,269 12/31/87 04/02/88 16.30 -0- 4. A.E. Partners 1988 21 617,050 135,450 752,500 12/31/88 04/02/89 15.30 -0- 5. A.E. Partners 1989 21 550,000 120,731 670,731 12/31/89 04/02/90 14.30 -0- 6. A.E. Partners 1990 27 887,500 244,622 1,132,122 12/31/90 04/02/91 13.30 -0- 7. A.E. Nineties-10 60 2,200,000 484,380 2,684,380 12/31/90 03/31/91 13.08 -0- 8. A.E. Nineties-11 25 750,000 268,003 1,018,003 09/30/91 01/31/92 12.25 -0- 9. A.E. Partners 1991 26 868,750 318,063 1,186,813 12/31/91 04/02/92 12.08 -0- 10. A.E. Nineties-12 87 2,212,500 791,833 3,004,333 12/31/91 04/30/92 12.00 -0- 11. A.E. Nineties-JV 92 155 4,004,813 1,414,917 5,419,730 10/28/92 04/05/93 11.33 -0- 12. A.E. Partners 1992 21 600,000 176,100 776,100 12/14/92 07/02/93 10.83 -0- 13. A.E. Nineties-Public #1 221 2,988,960 528,934 3,517,894 12/31/92 07/15/93 10.58 -0- 14. A.E. Nineties-1993 Ltd. 125 3,753,937 1,264,183 5,018,120 10/08/93 02/10/94 10.25 -0- 15. A.E. Partners 1993 21 700,000 219,600 919,600 12/31/93 07/02/94 10.00 -0- 16. A.E. Nineties-Public #2 269 3,323,920 587,340 3,911,260 12/31/93 06/15/94 9.75 -0- 17. A.E. Nineties-14 263 9,940,045 3,584,027 13,524,072 08/11/94 01/10/95 9.25 -0- 18. A.E. Partners 1994 23 892,500 231,500 1,124,000 12/31/94 07/02/95 9.00 -0- 19. A.E. Nineties-Public #3 391 5,800,990 928,546 6,729,536 12/31/94 06/05/95 9.00 -0- 20. A.E. Nineties-15 244 10,954,715 3,435,936 14,390,651 09/12/95 02/07/96 8.17 -0- 21. A.E. Partners 1995 23 600,000 244,725 844,725 12/31/95 10/02/96 7.75 -0- 22. A.E. Nineties-Public #4 324 6,991,350 1,287,752 8,279,102 12/31/95 07/08/96 8.00 -0- 23. A.E. Nineties-16 274 10,955,465 1,643,320 12,598,785 07/31/96 01/12/97 7.33 -0- 24. A.E. Partners 1996 21 800,000 367,416 1,167,416 12/31/96 07/02/97 7.00 -0- 25. A.E. Nineties-Public #5 378 7,992,240 1,654,740 9,646,980 12/31/96 06/08/97 7.00 -0- 26. A.E. Nineties-17 217 8,813,488 2,113,947 10,927,435 08/29/97 12/12/97 6.42 -0- 27. A.E. Nineties-Public #6 393 9,901,025 1,950,345 11,851,370 12/31/97 06/08/98 6.00 -0- 28. A.E. Partners 1997 13 506,250 231,050 737,300 12/31/97 07/02/98 5.83 -0- 29. A.E. Nineties-18 225 11,391,673 3,448,751 14,840,424 07/31/98 01/07/99 5.08 -0- 30. A.E. Nineties-Public #7 366 11,988,350 3,812,150 15,800,500 12/31/98 07/10/99 4.75 -0- 31. A.E. Partners 1998 26 1,740,000 756,360 2,496,360 12/31/98 07/02/99 4.75 -0- 32. A.E. Nineties-19 288 15,720,450 4,776,598 20,497,048 09/30/99 01/14/00 4.25 -0- 33. A.E. Nineties-Public #8 380 11,088,975 3,148,181 14,237,156 12/31/99 06/09/00 3.75 -0- 34. A.E. Partners 1999 8 450,000 196,500 646,500 12/31/99 10/02/00 3.75 -0- 35. 1999 Viking Resources LP 131 4,555,210 1,678,038 6,233,248 12/31/99 06/01/00 3.75 -0- 36. Atlas America-Series 20 361 18,809,150 6,297,945 25,107,095 09/30/00 01/30/01 3.50 -0- 37. Atlas America - Public #9 530 14,905,465 5,563,527 20,468,992 12/31/00 07/13/01 3.10 -0- 38. Atlas America - Series 21-A 282 12,510,713 4,535,799 17,046,512 05/15/01 11/16/01 2.85 -0- 39. Atlas America - Series 21-B 360 17,411,825 6,442,761 23,854,586 09/19/01 03/02/02 2.25 -0- 40. Atlas America - Public #10 818 21,281,170 7,227,432 28,508,602 12/31/01 06/20/02 2.00 -0- 41. Atlas America - Series 22 258 10,156,375 3,481,591 13,637,966 05/31/02 11/12/02 1.50 -0- 42. Atlas America - Series 23 246 9,644,550 3,214,850 12,859,400 09/30/02 02/18/03 1.25 -0- 43. Atlas America - Public #11 1017 31,178,145 11,757,568 42,935,713 12/31/02 7/15/2003 1.00 -0- 44. Atlas America - Series #24-2003 (A) 325 14,363,955 4,949,143 19,313,098 05/31/03 12/05/03 .50 -0- 45. Atlas America - Series #24-2003 (B) 422 20,542,850 7,300,020 27,842,870 08/29/03 02/05/04 .25 -0- 46. Atlas America - Public #12-2003 1102 40,170,308 13,825,929 53,996,237 12/31/03 (1) (1) -0-
- --------------------------- (1) This program closed December 31, 2003, and its first distribution is expected in the Summer, 2004. 40 Table 2 reflects the drilling activity of previous development drilling partnerships sponsored by the managing general partner and its affiliates. All the wells were development wells. YOU SHOULD NOT ASSUME THAT THE PAST PERFORMANCE OF PRIOR PARTNERSHIPS IS INDICATIVE OF THE FUTURE RESULTS OF THE PARTNERSHIPS. TABLE 2 ------- WELL STATISTICS - DEVELOPMENT WELLS AS OF APRIL 15, 2004
GROSS WELLS (1) NET WELLS (2) --------------------- ------------------------- Partnership Oil Gas Dry (3) Oil Gas Dry (3) ----------- --- --- ------- --- --- ------- 1. Atlas L.P. #1 - 1985 0 6 1 0 2.83 0.50 2. A.E. Partners 1986 0 8 0 0 3.50 0.00 3. A.E. Partners 1987 0 9 0 0 4.10 0.00 4. A.E. Partners 1988 0 9 0 0 3.80 0.00 5. A.E. Partners 1989 0 10 0 0 3.30 0.00 6. A.E. Partners 1990 0 12 0 0 5.00 0.00 7. A.E. Nineties-10 0 12 0 0 11.50 0.00 8. A.E. Nineties-11 0 14 0 0 4.30 0.00 9. A.E. Partners 1991 0 12 0 0 4.95 0.00 10. A.E. Nineties-12 0 14 0 0 12.50 0.00 11. A.E. Nineties-JV 92 0 52 0 0 24.44 0.00 12. A.E. Partners 1992 0 7 0 0 3.50 0.00 13. A.E. Nineties-Public #1 0 14 0 0 14.00 0.00 14. A.E. Nineties-1993 Ltd. 0 20 1 0 19.40 1.00 15. A.E. Partners 1993 0 8 0 0 4.00 0.00 16. A.E. Nineties-Public #2 0 16 0 0 15.31 0.00 17. A.E. Nineties-14 0 53 2 0 53.00 2.00 18. A.E. Partners 1994 0 12 0 0 5.00 0.00 19. A.E. Nineties-Public #3 0 26 1 0 25.50 1.00 20. A.E. Nineties-15 0 61 1 0 55.50 1.00 21. A.E. Partners 1995 0 6 0 0 3.00 0.00 22. A.E. Nineties-Public #4 0 32 0 0 30.50 0.00 23. A.E. Nineties-16 0 51 6 0 40.50 4.50 24. A.E. Partners 1996 0 13 0 0 4.84 0.00 25. A.E. Nineties-Public #5 0 36 0 0 35.91 0.00 26. A.E. Nineties-17 0 47 5 0 42.00 3.50 27. A.E. Nineties-Public #6 0 55 0 0 44.45 0.00 28. A.E. Partners 1997 0 6 0 0 2.81 0.00 29. A.E. Nineties-18 0 63 0 0 58.00 0.00 30. A.E. Nineties-Public #7 0 64 0 0 57.50 0.00 31. A.E. Partners 1998 0 19 0 0 9.50 0.00 32. A.E. Nineties-19 0 82 4 0 75.75 4.00 33. A.E. Nineties-Public #8 0 58 0 0 54.66 0.00 34. A.E. Partners 1999 0 5 0 0 2.50 0.00 35. 1999 Viking Resources LP 0 23 2 0 23.00 2.00 36. Atlas America - Series 20 0 106 1 0 100.25 1.00 37. Atlas America - Public #9 0 83 2 0 78.75 2.00 38. Atlas America - Series 21-A 0 68 0 0 62.50 0.00 39. Atlas America - Series 21-B 0 89 2 0 84.05 1.00 40. Atlas America - Public #10 0 107 3 0 100.15 3.00 41. Atlas America - Series 22 0 51 1 0 49.55 1.00 42. Atlas America - Series 23 0 47 1 0 47.00 1.00 43. Atlas America - Public #11 0 167 0 0 160.50 0.00 44. Atlas America-Series #24-A (2003) 0 76 0 0 69.50 0.00 45. Atlas America-Series #24-B (2003) 0 122 0 0 114.00 1.00 46. Atlas America-Public #12-2003 0 227 0 0 215.25 0.00 --- ---- --- --- ------- ----- 0 2078 33 0 1841.85 29.50 === ==== === === ======= =====
- -------------------------------------------------------------------------------- (1) A "gross well" is one in which a leasehold interest is owned. (2) A "net well" equals the actual leasehold interest owned in one gross well divided by one hundred. For example, a 50% leasehold interest in a well is one gross well, but a .50 net well. (3) For purposes of this Table only, a "Dry Hole" means a well which is plugged and abandoned with or without a completion attempt because the operator has determined that it will not be productive of gas and/or oil in commercial quantities. 41 TABLE 3 PROVIDES INFORMATION CONCERNING THE OPERATING RESULTS OF PREVIOUS DEVELOPMENT DRILLING PARTNERSHIPS SPONSORED BY THE MANAGING GENERAL PARTNER AND ITS AFFILIATES. YOU SHOULD NOT ASSUME THAT THE PAST PERFORMANCE OF PRIOR PARTNERSHIPS IS INDICATIVE OF THE FUTURE RESULTS OF THE PARTNERSHIPS. TABLE 3 ------- INVESTOR OPERATING RESULTS - INCLUDING EXPENSES AS OF APRIL 15, 2004
TOTAL COSTS ---------------------------------- Cash Partnership Investor Capital(1) Operating(6) Admin. Direct Distributions(2)(4) ----------- ------------------- ------------ ------ ------ ------------------- 1. Atlas L.P. #1 - 1985 $600,000 $216,475 $44,297 $12,248 $1,504,151 2. A.E. Partners 1986 631,250 171,232 70,472 11,183 741,436 3. A.E. Partners 1987 721,000 171,009 60,369 11,258 614,845 4. A.E. Partners 1988 617,050 142,425 57,494 10,290 553,693 5. A.E. Partners 1989 550,000 137,899 61,763 9,880 749,723 6. A.E. Partners 1990 887,500 208,268 88,250 13,146 1,048,835 7. A.E. Nineties - 10 2,200,000 438,671 97,614 34,324 1,870,262 8. A.E. Nineties - 11 750,000 167,847 97,547 64,214 1,064,840 9. A.E. Partners 1991 868,750 186,453 114,312 22,807 1,141,452 10. A.E. Nineties - 12 2,212,500 442,792 96,655 129,368 2,042,300 11. A.E. Nineties - JV 92 4,004,813 738,452 152,967 221,420 4,317,754(3) 12. A.E. Partners 1992 600,000 105,709 56,888 11,202 770,786 13. A.E. Nineties - Public #1 2,988,960 466,011 96,730 115,595 2,348,228 14. A.E. Nineties - 1993 Ltd. 3,753,937 533,548 105,320 56,167 2,202,916 15. A.E. Partners 1993 700,000 137,687 42,000 10,575 932,424 16. A.E. Nineties - Public #2 3,323,920 457,162 84,047 74,802 2,186,133 17. A.E. Nineties - 14 9,940,045 1,388,847 268,666 70,906 5,915,233 18. A.E. Partners 1994 892,500 136,265 50,418 12,563 1,097,372 19. A.E. Nineties - Public #3 5,800,990 730,863 141,022 82,826 3,805,873 20. A.E. Nineties - 15 10,954,715 1,380,467 267,086 64,669 7,413,760 21. A.E. Partners 1995 600,000 79,767 19,308 7,862 375,832 22. A.E. Nineties - Public #4 6,991,350 852,102 156,650 76,155 3,208,284 23. A.E. Nineties - 16 10,955,465 1,179,641 199,916 82,003 5,211,320 24. A.E. Partners 1996 800,000 110,317 24,924 44,590 516,579 25. A.E. Nineties - Public #5 7,992,240 821,872 149,071 72,960 3,723,443 26. A.E. Nineties - 17 8,813,488 886,440 149,388 136,481 4,772,899 27. A.E. Nineties - Public #6 9,901,025 1,012,581 167,900 83,086 5,262,985 28. A.E. Partners 1997 506,250 63,609 13,979 29,983 352,675 29. A.E. Nineties - 18 11,391,673 1,114,969 177,084 265,676 5,427,641 30. A.E. Nineties - Public #7 11,988,350 1,005,886 149,236 60,530 4,205,922 31. A.E. Partners 1998 1,740,000 191,735 24,556 52,007 1,049,216 32. A.E. Nineties - 19 15,720,450 1,284,352 184,428 14,592 5,845,519 33. A.E. Nineties - Public #8 11,088,975 815,833 120,693 69,490 4,283,114 34. A.E. Partners 1999 450,000 32,843 3,834 8,909 330,554 35. 1999 Viking Resources LP 4,555,210 1,223,054 0 161,573 5,921,034 36. Atlas America - Series 20 18,809,150 2,187,898 189,323 108,437 11,340,178 37. Atlas America - Public #9 14,905,465 1,368,388 130,649 50,299 6,303,565 38. Atlas America - Series 21-A 12,510,713 799,509 87,913 9,307 4,022,073 39. Atlas America - Series 21-B 17,411,825 1,006,495 101,237 9,166 4,607,572 40. Atlas America - Public #10 21,281,170 1,082,289 110,560 40,580 6,062,384 41. Atlas America - Series 22 10,156,375 424,548 43,722 6,449 2,918,273 42. Atlas America - Series 23 (5) 9,644,550 362,084 35,445 6,258 2,206,421 43. Atlas America - Public #11 (5) 31,178,145 679,738 66,988 12,362 4,309,324 44. Atlas America - Series 24-2003 (A) (5) 14,363,955 151,056 16,144 558 716,891 45. Atlas America - Series 24-2003 (B) (5) 20,542,850 97,521 11,883 0 515,280 46. Atlas America - Public #12-2003 (5) 40,170,308 0 0 0 0
Latest Quarterly Cash Distribution Partnership Cash Return(4) As of Date of Table ----------- -------------- ------------------- 1. Atlas L.P. #1 - 1985 251% $14,104 2. A.E. Partners 1986 117% 9,733 3. A.E. Partners 1987 85% 7,981 4. A.E. Partners 1988 90% 7,079 5. A.E. Partners 1989 136% 8,441 6. A.E. Partners 1990 118% 17,093 7. A.E. Nineties - 10 85% 32,438 8. A.E. Nineties - 11 142% 9,743 9. A.E. Partners 1991 131% 16,499 10. A.E. Nineties - 12 92% 26,285 11. A.E. Nineties - JV 92 108% 51,979 12. A.E. Partners 1992 128% 9,281 13. A.E. Nineties - Public #1 79% 30,587 14. A.E. Nineties - 1993 Ltd. 59% 14,845 15. A.E. Partners 1993 133% 13,710 16. A.E. Nineties - Public #2 66% 41,751 17. A.E. Nineties - 14 60% 87,594 18. A.E. Partners 1994 123% 20,618 19. A.E. Nineties - Public #3 66% 60,646 20. A.E. Nineties - 15 68% 143,684 21. A.E. Partners 1995 63% 5,913 22. A.E. Nineties - Public #4 46% 70,780 23. A.E. Nineties - 16 48% 133,479 24. A.E. Partners 1996 65% 15,346 25. A.E. Nineties - Public #5 47% 87,600 26. A.E. Nineties - 17 54% 142,539 27. A.E. Nineties - Public #6 53% 163,317 28. A.E. Partners 1997 70% 12,496 29. A.E. Nineties - 18 48% 184,035 30. A.E. Nineties - Public #7 7% 156,266 31. A.E. Partners 1998 60% 36,381 32. A.E. Nineties - 19 37% 251,126 33. A.E. Nineties - Public #8 39% 153,027 34. A.E. Partners 1999 73% 9,253 35. 1999 Viking Resources LP 130% 221,569 36. Atlas America - Series 20 60% 497,486 37. Atlas America - Public #9 42% 419,264 38. Atlas America - Series 21-A 32% 380,829 39. Atlas America - Series 21-B 26% 508,916 40. Atlas America - Public #10 28% 710,395 41. Atlas America - Series 22 29% 427,910 42. Atlas America - Series 23 (5) 23% 394,761 43. Atlas America - Public #11 (5) 14% 1,582,250 44. Atlas America - Series 24-2003 (A) (5) 5% 461,919 45. Atlas America - Series 24-2003 (B) (5) 3% 515,280 46. Atlas America - Public #12-2003 (5) 0% 0
- -------------------------------------------------------------------------------- (1) There have been no partnership borrowings other than from the managing general partner. The approximate principal amounts of such borrowings are as follows: o A.E. Nineties-10 - $330,000; and o A.E. Nineties-11 - $125,000; and o A.E. Nineties-12 - $365,500. 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 $307,434 in accordance with the terms of the offering. (4) This column reflects total cash distributions beginning with the first production from the program as a percentage of the total amount invested in the program and includes the return of the investors' capital. (5) As of the date of this table there is not twelve months of production and/or not all of the wells are drilled or on-line to sell production. (6) Operating costs consist of gathering fees, water hauling fees, meter reading fees, repairs and maintenance, insurance and severance tax. 42 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 APRIL 15, 2004
Total Costs Managing General ------------------------------------ Cash Partnership Partner Capital Operating(3) Admin. Direct Distributions(1) ----------- --------------- ------------- ------ ------ ---------------- 1. Atlas L.P. #1 - 1985 $114,800 $41,233 $8,437 $2,333 $285,056 2. A.E. Partners 1986 120,400 32,616 13,423 2,130 141,457 3. A.E. Partners 1987 158,269 49,307 17,406 3,246 159,540 4. A.E. Partners 1988 135,450 45,868 18,516 3,314 144,061 5. A.E. Partners 1989 120,731 30,271 13,558 2,169 170,205 6. A.E. Partners 1990 244,622 69,423 0 0 402,138 7. A.E. Nineties - 10 484,380 146,224 0 0 663,660 8. A.E. Nineties - 11 268,003 71,934 41,806 22,462 334,892 9. A.E. Partners 1991 318,063 62,151 0 0 459,225 10. A.E. Nineties - 12 791,833 189,768 41,424 29,936 875,272 11. A.E. Nineties - JV 92 1,414,917 363,715 75,342 27,518 1,198,464 12. A.E. Partners 1992 176,100 35,236 0 0 348,141 13. A.E. Nineties - Public #1 528,934 147,161 30,546 24,697 686,999 14. A.E. Nineties - 1993 Ltd. 1,264,183 228,663 45,137 20,489 470,461 15. A.E. Partners 1993 219,600 45,896 0 0 362,234 16. A.E. Nineties - Public #2 587,340 144,367 26,541 23,622 525,326 17. A.E. Nineties - 14 3,584,027 684,059 132,328 27,745 1,728,629 18. A.E. Partners 1994 231,500 45,422 0 0 381,697 19. A.E. Nineties - Public #3 928,546 243,621 47,007 27,609 1,207,437 20. A.E. Nineties - 15 3,435,936 591,629 114,465 27,715 2,235,852 21. A.E. Partners 1995 244,725 26,589 0 0 133,438 22. A.E. Nineties - Public #4 1,287,752 284,034 52,217 25,385 886,838 23. A.E. Nineties - 16 1,643,320 323,086 54,754 17,654 1,030,252 24. A.E. Partners 1996 367,416 36,772 0 0 182,669 25. A.E. Nineties - Public #5 1,654,740 273,957 49,690 24,320 896,239 26. A.E. Nineties - 17 2,113,947 319,601 53,861 19,863 1,573,795 27. A.E. Nineties - Public #6 1,950,345 337,527 55,967 27,695 1,657,106 28. A.E. Partners 1997 231,050 21,203 0 0 123,988 29. A.E. Nineties - 18 3,448,751 512,723 81,433 9,301 2,290,037 30. A.E. Nineties - Public #7 3,812,150 451,920 67,048 27,195 970,091 31. A.E. Partners 1998 756,360 63,912 0 0 348,561 32. A.E. Nineties - 19 4,776,598 590,614 84,810 6,710 2,385,074 33. A.E. Nineties - Public #8 3,148,181 333,227 49,297 28,383 1,715,210 34. A.E. Partners 1999 196,500 10,948 0 0 110,631 35. 1999 Viking Resources LP 1,678,038 407,685 0 53,858 1,953,930 36. Atlas America - Series 20 6,297,945 809,223 70,023 40,107 4,194,398 37. Atlas America - Public #9 5,563,527 558,919 53,364 20,544 2,396,813 38. Atlas America - Series 21-A 4,535,799 408,822 44,953 4,759 2,056,651 39. Atlas America - Series 21-B 6,442,761 518,498 52,153 4,722 2,373,598 40. Atlas America - Public #10 7,227,432 509,315 52,028 19,096 2,852,899 41. Atlas America - Series 22 3,481,591 204,692 20,575 3,109 1,407,021 42. Atlas America - Series 23 (2) 3,214,850 170,396 16,680 2,945 1,038,337 43. Atlas America - Public #11 (2) 11,757,568 350,168 34,509 6,368 2,219,906 44. Atlas America - Series 24-2003(A) (2) 4,949,143 73,162 7,819 270 347,216 45. Atlas America - Series 24-2003(B) (2) $7,300,020 $48,512 $5,911 0 $256,327 46. Atlas America - Public #12-2003 (2) 13,825,929 0 0 0 0
Latest Quarterly Cash Distribution As of Partnership Cash Return Date of Table ----------- ----------- --------------------- 1. Atlas L.P. #1 - 1985 248% $2,687 2. A.E. Partners 1986 117% 1,854 3. A.E. Partners 1987 101% 2,301 4. A.E. Partners 1988 106% 2,280 5. A.E. Partners 1989 141% 1,853 6. A.E. Partners 1990 164% 6,674 7. A.E. Nineties - 10 137% 12,090 8. A.E. Nineties - 11 125% 4,176 9. A.E. Partners 1991 144% 6,805 10. A.E. Nineties - 12 111% 11,265 11. A.E. Nineties - JV 92 85% 25,602 12. A.E. Partners 1992 198% 3,835 13. A.E. Nineties - Public #1 130% 9,659 14. A.E. Nineties - 1993 Ltd. 37% 6,362 15. A.E. Partners 1993 165% 5,191 16. A.E. Nineties - Public #2 89% 13,184 17. A.E. Nineties - 14 48% 43,143 18. A.E. Partners 1994 165% 7,969 19. A.E. Nineties - Public #3 130% 20,215 20. A.E. Nineties - 15 65% 61,579 21. A.E. Partners 1995 55% 2,452 22. A.E. Nineties - Public #4 69% 23,593 23. A.E. Nineties - 16 63% 36,558 24. A.E. Partners 1996 50% 5,847 25. A.E. Nineties - Public #5 54% 29,200 26. A.E. Nineties - 17 74% 51,392 27. A.E. Nineties - Public #6 85% 54,439 28. A.E. Partners 1997 54% 4,663 29. A.E. Nineties - 18 66% 84,629 30. A.E. Nineties - Public #7 25% 35,707 31. A.E. Partners 1998 46% 13,460 32. A.E. Nineties - 19 50% 64,359 33. A.E. Nineties - Public #8 54% 62,504 34. A.E. Partners 1999 56% 3,754 35. 1999 Viking Resources LP 116% 55,392 36. Atlas America - Series 20 67% 186,792 37. Atlas America - Public #9 43% 174,637 38. Atlas America - Series 21-A 45% 194,734 39. Atlas America - Series 21-B 37% 262,169 40. Atlas America - Public #10 39% 334,305 41. Atlas America - Series 22 40% 206,313 42. Atlas America - Series 23 (2) 32% 185,774 43. Atlas America - Public #11 (2) 19% 794,173 44. Atlas America - Series 24-2003(A) (2) 7% 223,724 45. Atlas America - Series 24-2003(B) (2) 4% $256,327 46. Atlas America - Public #12-2003 (2) 0% 0
- ------------------------------------------------------------------------------- (1) All cash distributions were from the sale of gas and not sales of properties. (2) As of the date of this table there is not twelve months of production and/or not all wells are drilled or on-line to sell production. (3) Operating costs consist of gathering fees, water hauling fees, meter reading fees, repairs and maintenance, insurance and severance tax. 43 Table 4 sets forth the managing general partner's estimate of the federal tax savings to investors in the managing general partner's prior development drilling partnerships, based on the maximum marginal tax rate in each year, the share of tax deductions as a percentage of their subscriptions, and the aggregate cash distributions. YOU ARE URGED TO CONSULT WITH YOUR OWN TAX ADVISORS CONCERNING YOUR SPECIFIC TAX SITUATION AND SHOULD NOT ASSUME THAT THE PAST PERFORMANCE OF PRIOR PARTNERSHIPS IS INDICATIVE OF THE FUTURE RESULTS OF THE PARTNERSHIPS.
TABLE 4 SUMMARY OF INVESTOR TAX BENEFITS AND CASH DISTRIBUTION RETURNS AS OF APRIL 15, 2004 Estimated Federal Tax Savings From (1): 1st Year Eff ----------------------------------------------------------- Investor Tax Tax 1st Year I.D.C. Depletion Section 29 Partnership Capital Deduct.(2) Rate Deduct.(3) Allowance(3) Depreciation(3) Tax Credit(4) ----------- ------- ---------- ---- --------------- ----------- --------------- ------------- 1. Atlas L.P. #1 - 1985 $600,000 99% 50.0% $298,337 $126,232 N/A $55,915 2. A.E. Partners 1986 631,250 99% 50.0% 312,889 71,097 N/A 13,507 3. A.E. Partners 1987 721,000 99% 38.5% 356,895 54,110 N/A N/A 4. A.E. Partners 1988 617,050 99% 33.0% 244,351 48,831 N/A N/A 5. A.E. Partners 1989 550,000 99% 33.0% 179,685 67,943 N/A N/A 6. A.E. Partners 1990 887,500 99% 33.0% 275,125 96,201 N/A 281,660 7. A.E. Nineties - 10 2,200,000 100% 33.0% 726,000 160,070 N/A 521,602 8. A.E. Nineties - 11 750,000 100% 31.0% 232,500 99,280 N/A 329,800 9. A.E. Partners 1991 868,750 100% 31.0% 269,313 108,953 N/A 315,893 10. A.E. Nineties - 12 2,212,500 100% 31.0% 685,875 201,228 N/A 617,285 11. A.E. Nineties - JV 92 4,004,813 92.5% 31.0% 1,322,905 349,531 N/A 1,002,109 12. A.E. Partners 1992 600,000 100% 31.0% 186,000 78,318 N/A 224,631 13. A.E. Nineties - Public #1 2,988,960 80.5% 36.0% 877,511 219,356 254,729 N/A 14. A.E. Nineties - 1993 Ltd. 3,753,937 92.5% 39.6% 1,378,377 208,066 N/A N/A 15. A.E. Partners 1993 700,000 100% 39.6% 273,216 84,756 N/A N/A 16. A.E. Nineties - Public #2 3,323,920 78.7% 39.6% 1,036,343 192,901 279,039 N/A 17. A.E. Nineties - 14 9,940,045 95% 39.6% 3,739,445 506,883 N/A N/A 18. A.E. Partners 1994 892,500 100% 39.6% 353,430 80,838 N/A N/A 19. A.E. Nineties - Public #3 5,800,990 76.2% 39.6% 1,752,761 334,224 521,115 N/A 20. A.E. Nineties - 15 10,954,715 90.0% 39.6% 3,904,261 599,582 N/A N/A 21. A.E. Partners 1995 600,000 100% 39.6% 237,600 25,627 N/A N/A 22. A.E. Nineties - Public #4 6,991,350 80.0% 39.6% 2,214,860 290,353 537,551 N/A 23. A.E. Nineties - 16 10,955,465 86.8% 39.6% 3,361,289 410,746 868,417 N/A 24. A.E. Partners 1996 800,000 100% 39.6% 316,800 40,363 N/A N/A 25. A.E. Nineties - Public #5 7,992,240 84.9% 39.6% 2,530,954 301,268 578,516 N/A 26. A.E. Nineties - 17 8,813,488 85.2% 39.6% 2,966,366 383,214 415,744 N/A 27. A.E. Nineties - Public #6 9,901,025 80.0% 39.6% 3,166,406 431,114 639,248 N/A 28. A.E. Partners 1997 506,250 100% 39.6% 200,475 27,393 N/A N/A 29. A.E. Nineties - 18 11,391,673 90.0% 39.6% 4,030,884 289,916 380,121 N/A 30. A.E. Nineties - Public #7 11,988,350 85.0% 39.6% 4,043,670 294,269 517,298 N/A 31. A.E. Partners 1998 1,740,000 100.0% 39.6% 689,040 80,129 N/A N/A 32. A.E. Nineties - 19 15,720,450 90.0% 39.6% 5,602,767 424,685 426,553 N/A 33. A.E. Nineties - Public #8 11,088,975 85.0% 39.6% 3,734,654 328,084 437,497 N/A 34. A.E. Partners 1999 450,000 100.0% 39.6% 178,200 20,939 N/A N/A 35. 1999 Viking Resources LP 4,555,210 92.0% 39.6% 1,678,038 419,915 N/A N/A 36. Atlas America - Series 20 18,809,150 90.0% 39.6% 6,712,802 720,855 405,737 N/A 37. Atlas America - Public #9 14,905,465 90.0% 39.6% 5,349,744 438,302 N/A N/A 38. Atlas America - Series 21-A 12,510,713 91.0% 39.1% 4,468,617 255,134 198,934 N/A 39. Atlas America - Series 21-B 17,411,825 91.0% 39.1% 6,197,907 289,680 246,390 N/A 40. Atlas America - Public #10 21,281,170 91.0% 39.1% 7,550,729 371,759 419,544 N/A 41. Atlas America - Series 22 10,156,375 91.0% 38.6% 3,564,312 162,808 191,168 N/A 42. Atlas America - Series 23 (8) 9,644,550 91.0% 38.6% 3,404,803 121,594 164,846 N/A 43. Atlas America - Public #11 (8) 31,178,145 91.0% 38.6% 11,003,503 259,394 384,143 N/A 44. Atlas America - Series 24-2003(A) (8) 14,363,955 91.0% 35.0% 4,578,250 17,862 179,654 N/A 44. Atlas America - Series 24-2003(B) (8) $20,542,850 91.0% 35.0% $6,514,764 $4,978 $365,751 N/A 45. Atlas America - Public #12-2003 (8) 40,170,308 91.0% 35.0% 12,879,332 0 0 N/A
Total Cumulative Cash Distribution Cash Dist. Percent of Cash As of And Tax Dist. And Tax Partnership Total Date of Table(5)(6) Savings(5)(6) Savings to Date(5)(6)(7) ----------- ----- ------------------- ------------- ------------------------ 1. Atlas L.P. #1 - 1985 $480,484 $1,504,151 $1,984,635 331% 2. A.E. Partners 1986 397,493 741,436 1,138,929 180% 3. A.E. Partners 1987 411,005 614,845 1,025,851 142% 4. A.E. Partners 1988 293,182 553,693 846,875 137% 5. A.E. Partners 1989 247,628 749,723 997,352 181% 6. A.E. Partners 1990 652,986 1,048,835 1,701,821 192% 7. A.E. Nineties - 10 1,407,672 1,870,262 3,277,934 149% 8. A.E. Nineties - 11 661,580 1,064,840 1,726,420 230% 9. A.E. Partners 1991 694,159 1,141,452 1,835,611 211% 10. A.E. Nineties - 12 1,504,388 2,042,300 3,546,687 160% 11. A.E. Nineties - JV 92 2,674,545 4,317,754 6,992,299 175% 12. A.E. Partners 1992 488,950 770,786 1,259,736 210% 13. A.E. Nineties - Public #1 1,351,596 2,348,228 3,699,824 124% 14. A.E. Nineties - 1993 Ltd. 1,586,443 2,202,916 3,789,359 101% 15. A.E. Partners 1993 357,972 932,424 1,290,396 184% 16. A.E. Nineties - Public #2 1,508,282 2,186,133 3,694,416 111% 17. A.E. Nineties - 14 4,246,328 5,915,233 10,161,561 102% 18. A.E. Partners 1994 434,268 1,097,372 1,531,640 172% 19. A.E. Nineties - Public #3 2,608,101 3,805,873 6,413,974 111% 20. A.E. Nineties - 15 4,503,843 7,413,760 11,917,603 109% 21. A.E. Partners 1995 263,227 375,832 639,059 107% 22. A.E. Nineties - Public #4 3,042,764 3,208,284 6,251,047 89% 23. A.E. Nineties - 16 4,640,451 5,211,320 9,851,771 90% 24. A.E. Partners 1996 357,163 516,579 873,742 109% 25. A.E. Nineties - Public #5 3,410,738 3,723,443 7,134,180 89% 26. A.E. Nineties - 17 3,765,325 4,772,899 8,538,224 97% 27. A.E. Nineties - Public #6 4,236,768 5,262,985 9,499,754 96% 28. A.E. Partners 1997 227,868 352,675 580,543 115% 29. A.E. Nineties - 18 4,700,921 5,427,641 10,128,562 89% 30. A.E. Nineties - Public #7 4,855,237 4,205,922 9,061,159 76% 31. A.E. Partners 1998 769,169 1,049,216 1,818,385 105% 32. A.E. Nineties - 19 6,454,005 5,845,519 12,299,524 78% 33. A.E. Nineties - Public #8 4,500,235 4,283,114 8,783,348 79% 34. A.E. Partners 1999 199,139 330,554 529,692 118% 35. 1999 Viking Resources LP 2,097,953 5,921,034 8,018,987 176% 36. Atlas America - Series 20 7,839,394 11,340,178 19,179,572 102% 37. Atlas America - Public #9 5,788,046 6,303,565 12,091,610 81% 38. Atlas America - Series 21-A 4,922,685 4,022,073 8,944,757 71% 39. Atlas America - Series 21-B 6,733,978 4,607,572 11,341,550 65% 40. Atlas America - Public #10 8,342,032 6,062,384 14,404,416 68% 41. Atlas America - Series 22 3,918,288 2,918,273 6,836,562 67% 42. Atlas America - Series 23 (8) 3,691,243 2,206,421 5,897,664 61% 43. Atlas America - Public #11 (8) 11,647,040 4,309,324 15,956,364 51% 44. Atlas America - Series 24-2003(A) (8) 4,775,766 716,891 5,492,657 38% 44. Atlas America - Series 24-2003(B) (8) $6,885,493 $515,280 $7,400,773 36% 45. Atlas America - Public #12-2003 (8) 12,879,332 - 12,879,332 32%
- ------------------------------------------------------------------------------- 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. Atlas Resources anticipates that approximately 90% of an investor general partner's subscription to a partnership will be deductible in the year in which he invests. 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. 6. This column reflects total cash distributions beginning with the first production from the program and includes the return of investor's capital. 7. These percentages are calculated by dividing the entry for each partnership in the "Total Cash Dist. And Tax Savings" column by that partnership's entry in the "Investor Capital" column. 8. As of the date of this table there is not twelve months of production and/or not all wells are drilled or on-line to sell production. 44 Table 5 sets forth payments made to the managing general partners and its affiliates from its previous partnerships. TABLE 5 ------- SUMMARY OF PAYMENTS TO THE MANAGING GENERAL PARTNER AND AFFILIATES FROM PRIOR PARTNERSHIPS AS OF APRIL 15, 2004
Cumulative Leasehold Reimbursement Cumulative Drilling and Cumulative of General and Investor Gathering Completion Operator's Administrative Partnership Capital Fees(1) Costs(2) Charges Overhead ----------- -------- ---------- ------------ ---------- -------------- 1. Atlas L.P. #1 - 1985 $600,000 0 $600,000 $257,708 $52,734 2. A.E. Partners 1986 631,250 0 631,250 203,533 83,896 3. A.E. Partners 1987 721,000 0 721,000 220,315 77,776 4. A.E. Partners 1988 617,050 0 617,050 188,293 76,010 5. A.E. Partners 1989 550,000 0 550,000 168,170 75,320 6. A.E. Partners 1990 887,500 0 887,500 277,690 88,250 7. A.E. Nineties-10 2,200,000 0 2,200,000 584,895 97,614 8. A.E. Nineties-11 750,000 0 761,802(3) 239,781 139,353 9. A.E. Partners 1991 868,750 0 867,500 248,604 114,312 10. A.E. Nineties-12 2,212,500 0 2,272,017(3) 632,559 138,079 11. A.E. Nineties-JV 92 4,004,813 0 4,157,700 1,102,167 228,309 12. A.E. Partners 1992 600,000 0 600,000 140,945 56,888 13. A.E. Nineties-Public #1 2,988,960 0 3,026,348(3) 613,172 127,276 14. A.E. Nineties-1993 Ltd. 3,753,937 0 3,480,656(3) 762,211 150,458 15. A.E. Partners 1993 700,000 0 689,940 183,582 42,000 16. A.E. Nineties-Public #2 3,323,920 0 3,324,668(3) 601,529 110,588 17. A.E. Nineties-14 9,940,045 0 9,512,015(3) 2,072,906 400,994 18. A.E. Partners 1994 892,500 0 892,500 181,686 50,418 19. A.E. Nineties-Public #3 5,800,990 0 5,800,990 974,484 188,030 20. A.E. Nineties-15 10,954,715 0 9,859,244(3) 1,972,096 381,551 21. A.E. Partners 1995 600,000 0 600,000 106,355 19,308 22. A.E. Nineties-Public #4 6,991,350 0 6,991,350 1,136,135 208,866 23. A.E. Nineties-16 10,955,465 0 10,955,465 1,502,728 254,670 24. A.E. Partners 1996 800,000 0 800,000 147,089 24,924 25. A.E. Nineties-Public #5 7,992,240 0 7,992,240 1,095,829 198,761 26. A.E. Nineties-17 8,813,488 0 8,813,488 1,206,041 203,249 27. A.E. Nineties-Public #6 9,901,025 0 9,901,025 1,350,109 223,867 28. A.E. Partners 1997 506,250 0 506,250 84,812 13,979 29. A.E. Nineties-18 11,391,673 0 11,391,673 1,627,693 258,517 30. A.E. Nineties-Public #7 11,988,350 0 11,988,350 1,457,805 216,283 31. A.E. Partners 1998 1,740,000 0 1,740,000 255,646 24,556 32. A.E. Nineties-19 15,720,450 0 15,720,450 1,874,966 269,238 33. A.E. Nineties-Public #8 11,088,975 0 11,088,975 1,149,060 169,991 34. A.E. Partners 1999 450,000 0 450,000 43,791 3,834 35. 1999 Viking Resources LP 4,555,210 0 4,555,210 1,630,739 0 36. Atlas America-Series 20 18,809,150 0 18,809,150 2,997,121 259,346 37. Atlas America-Public #9 14,905,465 $703,321 14,905,465 1,223,985 184,013 38. Atlas America-Series 21-A 12,510,713 444,947 12,510,713 763,384 132,866 39. Atlas America-Series 21-B 17,411,825 544,397 17,411,825 922,858 153,390 40. Atlas America-Public #10 21,281,170 736,138 21,281,170 855,466 162,589 41. Atlas America-Series 22 10,156,375 292,089 10,156,375 337,151 64,298 42. Atlas America-Series 23 9,644,550 257,748 9,644,550 274,732 52,125 43. Atlas America-Public #11 31,178,145 535,609 31,178,145 494,297 101,497 44. Atlas America - Series 24-2003 (A) 14,363,955 85,263 14,363,955 138,955 23,963 45. Atlas America - Series 24-2003 (B) 20,542,850 50,436 20,542,850 95,597 17,794 46. Atlas America - Public 12-2003 40,170,308 0 40,170,308 0 0
- -------------------------------------------------------------------------------- (1) The amount of gathering fees paid to the managing general partner and its affiliates from 2001 to the date of this table are shown for those partnerships which began operations on or after December 31, 2000. The books and records of the earlier partnerships do not separately allocate all of the gathering fees paid by them. Additional information concerning the gathering fees paid by those partnerships will be provided to you on written request to the managing general partner. (2) Excluding the managing general partner's capital contributions. (3) Includes additional drilling costs paid with production revenues. 45 MANAGEMENT MANAGING GENERAL PARTNER AND OPERATOR The partnerships will have no officers or directors. Instead, Atlas Resources, Inc., a Pennsylvania corporation which was incorporated in 1979, will serve as the managing general partner of each partnership. Atlas Resources' affiliate Atlas Energy Group, Inc., an Ohio corporation which was the first of the Atlas group of companies, was incorporated in 1973. Atlas Energy Group, Inc. will serve as the partnership's general drilling contractor and operator in Ohio. As of March 1, 2004, the managing general partner and its affiliates operated approximately 4,653 natural gas and oil wells located in Ohio, Pennsylvania and New York. Since 1985 the managing general partner has sponsored 12 public and 35 private partnerships to conduct natural gas drilling and development activities in Pennsylvania, Ohio, and New York. 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. Atlas Resources has a 97% completion rate for wells drilled by its development partnerships. In September 1998, Atlas Energy Group, Inc., the former parent company of the managing general partner, merged into Atlas America, Inc., a Delaware holding company. Atlas America is a subsidiary of Resource America, Inc., a publicly-traded company, which is sometimes referred to in this prospectus as Resource America. Resource America, Inc. recently conducted an offering of a portion of its common stock (the "shares") in Atlas America, the Delaware holding company. The Atlas America public offering of 2,300,000 shares was priced on May 10, 2004 at $15.50 per share and raised $33.2 million of net proceeds. The shares began trading on NASDAQ on May 11, 2004 under the symbol "ATLS." On June 1, 2004, the underwriters announced their exercise in full of their over-allotment option related to the offering of 345,000 shares. The exercise of the over-allotment generated additional net offering proceeds of approximately $5 million, bringing the total net proceeds for the offering to approximately $38.2 million and the total number of shares sold to 2,645,000, thus reducing Resource America's ownership of Atlas America to approximately 80.2%. The net proceeds of the offering, after deducting underwriting discounts, was or will be distributed to Resource America in the form of a repayment of inter-company debt and a non-taxable dividend. Also, on May 14, 2004, in connection with the Atlas America offering, the following officers and key employees of the managing general partner and Atlas America set forth in "- Officers, Directors and Other Key Personnel," below, resigned their positions with Resource America and all of its subsidiaries which are not also subsidiaries of Atlas America: Mr. Freddie M. Kotek, Mr. Frank P. Carolas, Mr. Jeffrey C. Simmons, Ms. Nancy J. McGurk, Mr. Michael L. Staines, and Ms. Marci Bleichmar. Resource America has advised the managing general partner that it intends to distribute its remaining ownership interest in Atlas America to its common stockholders. Resource America expects the distribution to take the form of a spin-off by means of a special dividend to Resource America common stockholders of all of Atlas America's common stock owned by Resource America. Resource America further has advised the managing general partner that it anticipates that the distribution will occur by the end of 2004. Resource America has sole discretion if and when to complete the distribution and its terms. Resource America does not intend to complete the distribution unless it receives a ruling from the Internal Revenue Service and/or an opinion from its tax counsel as to the tax-free nature of the distribution to Resource America and its stockholders for U.S. federal income tax purposes. The Internal Revenue Service requirements for tax-free distributions of this nature are complex and the Internal Revenue Service has broad discretion, so there is significant uncertainty as to whether Resource America will be able to obtain such a ruling. Because of this uncertainty and the fact that the timing and completion of the distribution is in Resource America's sole discretion, the distribution may not occur by the contemplated time or may not occur at all. If the distribution occurs, the managing general partner believes the principal effect on Atlas America will be that Resource America will no longer own any of Atlas America's common stock and, thus, will no longer be in a position to determine the outcome of corporate actions requiring stockholder approval such as: o the election and removal of directors; o mergers or other business combinations involving Atlas America; 46 o future issuances of Atlas America's common stock or other securities; and o amendments to Atlas America's certificate of incorporation and bylaws. These actions will be passed on by Atlas America's stockholders existing at the record dates for such matters. Resource America's rights following the distribution will be defined by agreements between Resource America and Atlas America. Atlas America 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. OFFICERS, DIRECTORS AND OTHER 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 - ---- --- ------------------ Freddie M. Kotek 48 Chairman of the Board of Directors, Chief Executive Officer and President Frank P. Carolas 44 Executive Vice President - Land and Geology and a Director Jeffrey C. Simmons 45 Executive Vice President - Operations and a Director Jack L. Hollander 48 Senior Vice President - Direct Participation Programs Nancy J. McGurk 48 Senior Vice President, Chief Financial Officer and Chief Accounting Officer Michael L. Staines 54 Senior Vice President, Secretary and a Director Michael G. Hartzell 48 Vice President - Land Administration Donald R. Laughlin 56 Vice President - Drilling and Production Marci F. Bleichmar 33 Vice President of Marketing Sherwood S. Lutz 53 Senior Geologist/Manager of Geology Michael W. Brecko 46 Director of Energy Sales Karen A. Black 43 Vice President - Partnership Administration Justin T. Atkinson 31 Director of Due Diligence Winifred C. Loncar 63 Director of Investor Services
With respect to the biographical information set forth below: o the approximate amount of an individual's professional time devoted to the business and affairs of the managing general partner and Atlas America have been aggregated because there is no reasonable method for them to distinguish their activities between the two companies; and o for those individuals who also hold senior positions with other affiliates of the managing general partner, if it is stated that they devote approximately 100% of their professional time to the managing general partner and Atlas America, it is because either the other affiliates are not currently active in drilling new wells, such as Viking Resources or Resource Energy, and the individuals are not required to devote a material amount of their professional time to the affiliates, or there is no reasonable method to distinguish their activities between the managing general partner and Atlas America as compared with the other affiliates of the managing general partner, such as Viking Resources or Resource Energy. FREDDIE M. KOTEK. President and Chief Executive Officer since January 2002 and Chairman of the Board of Directors since September 2001. Mr. Kotek has been Executive Vice President and Chief Financial Officer of Atlas America since February 2004 and served as a director from September 2001 until February 2004. Mr. Kotek was a Senior Vice President of Resource America and President of Resource Leasing, Inc. (a wholly-owned subsidiary of Resource America) from 1995 until May 2004 when he resigned from Resource America and all of its subsidiaries which are not subsidiaries of Atlas America. Mr. Kotek was President of Resource Properties from September 2000 to October 2001 and its Executive Vice President from 1993 to August 1999. Mr. Kotek received a Bachelor of Arts degree from Rutgers College in 1977 with high honors in Economics. He also received a Master in Business Administration degree from the Harvard Graduate School of Business Administration in 1981. Mr. Kotek will devote approximately 95% of his professional time to the business and affairs of the managing general partner and Atlas America, and the remainder of his professional time to the business and affairs of the managing general partner's affiliates. 47 FRANK P. CAROLAS. Executive Vice President-Land and Geology and a Director since January 2001. Mr. Carolas has been an Executive Vice President of Atlas America since January 2001 and served as a Director of Atlas America from January 2002 until February 2004. Mr. Carolas was a Vice President of Resource America from April 2001 until May 2004 when he resigned from Resource America. Mr. Carolas served as Vice President of Land and Geology for the managing general partner from July 1999 until December 2000 and for Atlas America from 1998 until December 2000. Before that Mr. Carolas served as Vice President of Atlas Energy Group, Inc. from 1997 until 1998, which was the former parent company of the managing general partner. Mr. Carolas is a certified petroleum geologist and has been with the managing general partner and its affiliates since 1981. He received a Bachelor of Science degree in Geology from Pennsylvania State University in 1981 and is an active member of the American Association of Petroleum Geologists. Mr. Carolas devotes approximately 100% of his professional time to the business and affairs of the managing general partner and Atlas America. JEFFREY C. SIMMONS. Executive Vice President-Operations and a Director since January, 2001. Mr. Simmons has been an Executive Vice President of Atlas America since January 2001 and was a Director of Atlas America from January 2002 until February 2004. Mr. Simmons was a Vice President of Resource America from April 2001 until May 2004 when he resigned from Resource America. Mr. Simmons served as Vice President of Operations for the managing general partner from July 1999 until December 2000 and for Atlas America from 1998 until December 2000. Mr. Simmons joined Resource America in 1986 as a senior petroleum engineer and has served in various executive positions with its energy subsidiaries since then. 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 in 1981 and his Masters degree in Business Administration from Ashland University in 1992. Mr. Simmons devotes approximately 80% of his professional time to the business and affairs of the managing general partner and Atlas America, and the remainder of his professional time to the business and affairs of the managing general partner's affiliates, primarily Viking Resources and Resource Energy. JACK L. HOLLANDER. Senior Vice President - Direct Participation Programs since January 2002 and before that he served as Vice President - Direct Participation Programs from January 2001 until December 2001. Mr. Hollander also serves as Senior Vice President - Direct Participation Programs of Atlas America since January 2002. Mr. Hollander practiced law with Rattet, Hollander & Pasternak, concentrating in tax matters and real estate transactions, from 1990 to January 2001, and served as in-house counsel for Integrated Resources, Inc. (a diversified financial services company) from 1982 to 1990. Mr. Hollander earned a Bachelor of Science degree from the University of Rhode Island in 1978, his law degree from Brooklyn Law School in 1981, and a Master of Law degree in Taxation from New York University School of Law Graduate Division in 1982. Mr. Hollander is a member of the New York State bar, the Investment Program Association, and the Financial Planning Association. Mr. Hollander devotes approximately 100% of his professional time to the business and affairs of the managing general partner and Atlas America. NANCY J. MCGURK. Senior Vice President since January 2002, Chief Financial Officer and Chief Accounting Officer since January 2001. Ms. McGurk also serves as Senior Vice President since January 2002 and Chief Accounting Officer of Atlas America since January 2001. Ms. McGurk served as Chief Financial Officer for Atlas America from January 2001 until February 2004. Ms. McGurk was a Vice President of Resource America from 1992 until May 2004 and its Treasurer and Chief Accounting Officer from 1989 until May 2004 when she resigned from Resource America. Also, since 1995 Ms. McGurk has served as Vice President - Finance of Resource Energy, Inc. Ms. McGurk received a Bachelor of Science degree in Accounting from Ohio State University in 1978, and has been a Certified Public Accountant since 1982. Ms. McGurk will devote approximately 80% of her professional time to the business and affairs of the managing general partner and Atlas America, and the remainder of her professional time to the business and affairs of the managing general partner's affiliates. 48 MICHAEL L. STAINES. Senior Vice President, Secretary, and a Director since 1998. Mr. Staines has been an Executive Vice President and Secretary of Atlas America since 1998. Mr. Staines was a Senior Vice President of Resource America from 1989 until May 2004 when he resigned from Resource America. Mr. Staines was a director of Resource America from 1989 to February 2000 and Secretary from 1989 to October 1998. Mr. Staines has been President of Atlas Pipeline Partners GP since January 2001 and its Chief Operating Officer and a member of its Managing Board since its formation in November 1999. 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. Mr. Staines will devote approximately 5% of his professional time to the business and affairs of the managing general partner and Atlas America, and the remainder of his professional time to the business and affairs of the managing general partner's affiliates, including Atlas Pipeline Partners GP. MICHAEL G. HARTZELL. Vice President - Land Administration since September 2001. Mr. Hartzell has been Vice President - Land Administration of Atlas America since January 2002, and before that served as Senior Land Coordinator from January 1999 to January 2002. Mr. Hartzell has been with the managing general partner and its affiliates since 1980 when he began his career as a land department representative. Mr. Hartzell manages all Land Department functions. Mr. Hartzell serves on the Environmental Committee of the Independent Oil and Gas Association of Pennsylvania and is a past Chairman of the Committee. Mr. Hartzell devotes approximately 100% of his professional time to the business and affairs of the managing general partner and Atlas America. DONALD R. LAUGHLIN. Vice President-Drilling and Production since September 2001. Mr. Laughlin also serves as Vice President - Drilling and Production for Atlas America since January 2002, and before that served as Senior Drilling Engineer since May 2001 when he joined Atlas America. Mr. Laughlin has over thirty years of experience as a petroleum engineer in the Appalachian Basin, having been employed by Columbia Gas Transmission Corporation from October 1995 to May 2001 as a senior gas storage engineer and team leader, Cabot Oil & Gas Corporation from 1989 to 1995 as Manager of Drilling Operations and Technical Services, Doran & Associates, Inc. (an industrial engineering firm) from 1977 until 1989 as Vice President--Operations, and Columbia Gas from 1970 to 1977 as Drilling Engineer and Gas Storage Engineer. Mr. Laughlin received his Petroleum Engineering degree from the University of Pittsburgh in 1970. He is a member of the Society of Petroleum Engineers. Mr. Laughlin devotes approximately 100% of his professional time to the business and affairs of the managing general partner and Atlas America. MARCI F. BLEICHMAR. Vice President of Marketing since February 2001. Ms. Bleichmar also serves as Vice President of Marketing for Atlas America since February 2001 and was with Resource America from February 2001 until May 2004 when she resigned from Resource America. From March 2000 until February 2001, Ms. Bleichmar served as Director of Marketing for Jacob Asset Management (a mutual fund manager), and from March 1998 until March 2000, she was an account executive at Bloomberg Financial Services LP. From November 1994 until 1998, Ms. Bleichmar was an Associate on the Derivatives Trading Desk of JP Morgan. Ms. Bleichmar received a Bachelor of Arts degree from the University of Wisconsin in 1992. Ms. Bleichmar devotes approximately 100% of her professional time to the business and affairs of the managing general partner and Atlas America. SHERWOOD S. LUTZ. Senior Geologist/Manager of Geology. In 1996 Mr. Lutz joined Viking Resources, which was purchased by Resource America in 1999 as senior geologist. Since 1999 Mr. Lutz has been a senior geologist for the managing general partner and Atlas America. Mr. Lutz received his Bachelor of Science degree in Geological Sciences from the Pennsylvania State University in 1973. Mr. Lutz is a certified petroleum geologist with the American Association of Petroleum Geologists as well as a licensed professional geologist in Pennsylvania. Mr. Lutz devotes approximately 100% of his professional time to the business and affairs of the managing general partner and Atlas America. MICHAEL W. BRECKO. Director of Energy Sales since November 2002. Mr. Brecko has over 16 years of natural gas marketing experience in the oil and natural gas industry. Mr. Brecko is a 1980 graduate from The Pennsylvania State University with a Bachelor of Science degree in Civil Engineering. His career in natural gas marketing began when he joined Equitable Gas Company, a local distribution company, as a marketing representative in the commercial/ industrial marketing division from May 1986 to August 1992. He subsequently joined O&R Energy, a subsidiary of Orange and Rockland Utilities, as regional marketing manager from August 1992 to November 1993. Beginning in December 1993 through July 2001, Mr. Brecko worked for Cabot Oil & Gas Corporation, a mid-sized Appalachian oil and natural gas producer, as an account executive and he was promoted in August 1998 to natural gas trader. In November 2001, he joined Sprague Energy Corporation, a multi-energy sourced company, as a regional account manager before joining Atlas America in 2002. Mr. Brecko devotes approximately 100% of his professional time to the business and affairs of the managing general partner and Atlas America. 49 KAREN A. BLACK. Vice President - Partnership Administration since February 2003. Ms. Black is also Vice President and Financial and Operations Principal of Anthem Securities since October 2002. Ms. Black joined the managing general partner and Atlas America in July 2000 and served as manager of production, revenue and partnership accounting from July 2000 through October 2001, after which she served as manager and financial analyst until her appointment as Vice President - Partnership Administration. Before joining the managing general partner in 2000, Ms. Black was associated with Texas Keystone, Inc. as controller from April 1997 through June 2000. Ms. Black was employed as a tax accountant for Sobol Bosco & Associates, Inc. from May 1996 through March 1997. Ms. Black received a Bachelor of Arts degree from the University of Pittsburgh, Johnstown in 1982. Ms. Black devotes approximately 50% of her professional time to the business and affairs of the managing general partner and Atlas America, and the remainder of her professional time to the business and affairs of Anthem Securities. JUSTIN T. ATKINSON. Director of Due Diligence since February 2003. Mr. Atkinson also serves as President of Anthem Securities since February 2004 and as Chief Compliance Officer since October 2002. Before that Mr. Atkinson served as assistant compliance officer of Anthem Securities from December 2001 until October 2002 and Vice President from October 2002 until February 2004. Before his employment with the managing general partner, Mr. Atkinson was a manager of investor and broker/dealer relations with Viking Resources Corporation from 1996 until November 2001. Mr. Atkinson earned a Bachelor of Arts degree in Business Management in 1995 from Walsh University in North Canton, Ohio. Mr. Atkinson devotes approximately 25% of his professional time to the business and affairs of the managing general partner and Atlas America, and the remainder of his professional time to the business and affairs of Anthem Securities. WINIFRED C. LONCAR, Director of Investor Services since February 2003. Ms. Loncar previously held the position of manager of investor services from the inception of the investor service department in 1990 to February 2003. Before that she was executive secretary to the managing general partner. Ms. Loncar received a Bachelor of Science degree in Business from Point Park University in 1998. Ms. Loncar devotes approximately 100% of her professional time to the business and affairs of the managing general partner and Atlas America. ATLAS AMERICA, INC., A DELAWARE HOLDING COMPANY As of February 2004, the officers and directors for Atlas America include the following:
NAME AGE POSITION ---- --- -------- Edward E. Cohen 65 Chairman, Chief Executive Officer and President Frank P. Carolas 44 Executive Vice President Freddie M. Kotek 48 Executive Vice President and Chief Financial Officer Jeffrey C. Simmons 45 Executive Vice President Michael L. Staines 54 Executive Vice President and Secretary Nancy J. McGurk 48 Senior Vice President and Chief Accounting Officer Jonathan Z. Cohen 33 Vice Chairman Carlton M. Arrendell 42 Director William R. Bagnell 41 Director Donald W. Delson 53 Director Nicholas DiNubile 51 Director Dennis A. Holtz 63 Director
50 See "- Officers, Directors and Other Key Personnel," above, for biographical information on certain of these individuals who are also officers of the managing general partner. Biographical information on the other officers and directors will be provided by the managing general partner on request. As of June 1, 2004, the managing general partner and its affiliates under Atlas America employ a total of approximately 205 persons. The technical team has 10 geologists and engineers which averages 22 years of industry experience, principally in the Appalachian Basin. At December 31, 2003 Atlas America and its affiliates had more than $514 million of energy assets under management. ORGANIZATIONAL DIAGRAM AND SECURITY OWNERSHIP OF BENEFICIAL OWNERS See "- Managing General Partner and Operator" above for a discussion of Atlas America's stock offering and the percentage of stock owned by Resource America in Atlas America, the Delaware holding company, which owns 100% of the common stock of AIC, Inc., which owns 100% of the common stock of the managing general partner. The directors of AIC, Inc. are Jonathan Z. Cohen, Michael L. Staines, and Jeffrey C. Simmons. The biographies of Messrs. Staines, and Simmons are set forth above. This organizational diagram does not include all of the subsidiaries of Resource America, as discussed above.
------------------------------------------ Resource America, Inc. ------------------------------------------ | ------------------------------------------ Atlas Energy Holdings, Inc. ------------------------------------------ | ------------------------------------------ Atlas America, Inc. (Delaware) (holding company) (1) ------------------------------------------ | --------------------------------------------------------------------------------------------------------------- | | | | | - -------------------- -------------------- ------------------------- --------------------- -------------------- Viking AIC, Inc. Atlas America, Inc. Resource Energy, Atlas Noble Resources (Pennsylvania) Inc. (2) Corporation (2) Corporation (2) (operating company) - -------------------- -------------------- ------------------------- --------------------- -------------------- | -------------------------------------------------------------------------------------------------------------- | | | | | - ----------------------- -------------------- -------------------- -------------------- ------------------- Atlas Resources, Inc., Atlas Energy Pennsylvania Anthem Securities, Atlas Energy managing general Corporation, Industrial Energy, Inc., registered Group, Inc., partner of Atlas managing general Inc. broker/dealer and driller and America Public partner of dealer-manager operator in Ohio #14-2004 Program, exploratory driller and operator drilling in Pennsylvania partnerships and driller and operator - ----------------------- -------------------- -------------------- -------------------- ------------------- | | - ----------------------- ------------------- ARD Investments, AED Investments, Inc. Inc. - ----------------------- -------------------
- ----------------- (1) See "- Managing General Partner and Operator," above, for the discussion of Atlas America's stock offering. (2) Viking Resources, Resource Energy, and Atlas Noble Corporation are also engaged in the oil and gas business. Resource Energy has been an energy subsidiary of Resource America since 1993. Resource America acquired Viking Resources in August 1999, and Atlas Noble Corporation was formed in October 2000 after Resource America acquired all of the assets of Kingston Oil Corporation. Atlas America manages their assets and employees including sharing common employees. Also, many of the officers and directors of the managing general partner serve as officers and directors of those entities. 51 REMUNERATION No officer or director of the managing general partner will receive any direct remuneration or other compensation from the partnerships. These persons will receive compensation solely from affiliated companies of the managing general partner. CODE OF BUSINESS CONDUCT AND ETHICS Because the partnerships do not directly employ any persons, the managing general partner has determined that the partnerships will rely on a Code of Business Conduct and Ethics adopted by Resource America, Inc. that applies to the principal executive officer, principal financial officer and principal accounting officer of the managing general partner, as well as to persons performing services for the managing general partner generally. You may obtain a copy of this code of ethics by a request to the managing general partner at Atlas Resources, Inc., 311 Rouser Road, Moon Township, Pennsylvania 15108. TRANSACTIONS WITH MANAGEMENT AND AFFILIATES The managing general partner depends on its parent company, Atlas America, for management and administrative functions and financing for capital expenditures. The managing general partner pays a management fee to Atlas America for management and administrative services, which amounted to $13.1 million, $10.5 million and $6.4 million for the years ended September 30, 2003, 2002 and 2001, respectively. (See "Financial Information Concerning the Managing General Partner and Atlas America Public #14-2004 L.P.") The managing general partner and its officers, directors and affiliates have in the past invested, and may in the future invest, in partnerships sponsored by the managing general partner. They may also subscribe for units in each partnership as described in "Plan of Distribution." MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION, RESULTS OF OPERATIONS, LIQUIDITY AND CAPITAL RESOURCES None of the partnerships composing the program have been formed other than the first partnership, Atlas America Public #14-2004 L.P. Each partnership will be formed as a limited partnership under the Delaware Revised Uniform Limited Partnership Act before the initial closing of the partnership and breaking escrow as discussed in "Terms of the Offering - Activation of the Partnerships." Thus, the partnerships formed or to be formed have not included any historical information in this prospectus since they: o have no net worth; o do not own any properties on which wells will be drilled; o have no third-party investors; and o have not conducted any operations. (See "Capitalization and Source of Funds and Use of Proceeds," "Proposed Activities," "Competition, Markets and Regulation," and "Financial Information Concerning the Managing General Partner and Atlas America Public #14-2004 L.P.") Each partnership will depend on the proceeds of this offering and the managing general partner's capital contributions to carry out its proposed activities. Each partnership intends to use its subscription proceeds to pay the intangible drilling costs, the investors' share of equipment costs, and the investors' share of any cost overruns of drilling and completing the partnership's wells. 52 The managing general partner believes that each partnership's liquidity requirements will be satisfied from the following: o the subscription proceeds of this offering; o the managing general partner's capital contributions; o the cash flow from future operations; and o partnership borrowings, if necessary. The managing general partner also anticipates that no additional funds will be required for operating costs before a partnership begins receiving production revenues from its wells. Substantially all of the subscription proceeds of you and the other investors in a partnership will be committed or expended after the offering of the partnership closes. If a partnership requires additional funds for cost overruns or additional development or remedial work after a well begins producing, then these funds may be provided by: o subscription proceeds, if available, drilling fewer wells, or acquiring a lesser working interest in one or more wells; o borrowings from the managing general partner or its affiliates; or o retaining partnership revenues. There will be no borrowings from third-parties. The amount that may be borrowed by a partnership from the managing general partner and its affiliates may not at any time exceed 5% of the partnership's subscription proceeds from you and the other investors and must be without recourse to you and the other investors. 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 a partnership, which it is not required to do, then: o 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 o 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, Atlas America (the "borrower") has a $75 million revolving credit facility with a group of banks with Wachovia Bank, N.A. as the agent and issuing bank. The managing general partner, Resource America and various energy subsidiaries of Atlas America are guarantors of the credit agreement. As of March 2004, this facility has a borrowing base of $65 million, which may be increased to $75 million subject to growth in the oil and gas reserves of the borrower and the guarantors. Borrowings under the facility are collateralized by substantially all of the assets of Atlas America, the managing general partner and the other guarantors. This includes the managing general partner's interests in its partnerships, but does not include any investor's interest in a partnership. A breach of the credit agreement by the borrower constitutes a default under the loan. The credit facility has a term ending in July 2005. At December 31, 2003, the borrower had an outstanding balance of approximately $19 million and also had a $1.7 million letter of credit issued under the facility. The managing general partner depends on its parent company, Atlas America, for management and administrative functions and financing for capital expenditures. The managing general partner pays a management fee to Atlas America for management and administrative services, as described in "Management - Transactions with Management and Affiliates." See the footnotes to the managing general partner's audited financial statements and the footnotes to the managing general partner's unaudited financial statements for more details concerning the credit facility and inter-company borrowings in "Financial Information Concerning the Managing General Partner and Atlas America Public #14-2004 L.P." 53 PROPOSED ACTIVITIES OVERVIEW OF DRILLING ACTIVITIES The managing general partner anticipates that the subscription proceeds of each partnership will be used to drill primarily natural gas development wells, which means a well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive. Stratigraphic means a layer of rock which has characteristics that differentiate it from the rocks above and below it. Stratigraphic horizon generally means that part of a formation or layer of rock with sufficient porosity and permeability to form a petroleum reservoir. Currently, the partnerships do not hold any interests in any properties or prospects on which the wells will be drilled. Although the majority of the wells will be classified as natural gas wells, which may produce a small amount of oil, some of the wells, such as those in McKean County, Pennsylvania, may be classified as oil or combination oil and natural gas wells. Each partnership will be a separate business entity from the other partnerships, and you will be a partner only in the partnership in which you invest. You will have no interest in the business, assets or tax benefits of the other partnerships unless you also invest in the other partnerships. Thus, your investment return will depend solely on the operations and success or lack of success of the particular partnership in which you invest. Each partnership generally will drill different wells, but they may own working interests and participate in drilling and completing one or more of the same wells. The number of wells to be drilled by a partnership cannot be determined precisely before the funding of a partnership and is determined primarily by: o the amount of subscription proceeds raised for that partnership; o the geographical areas in which wells are drilled by that partnership; o the partnership's percentage of working interest owned in the wells, which could range from 25% to 100%; and o the cost of the wells, including if there are any cost overruns for intangible drilling costs of the wells which are paid 100% by you and the other investors in that partnership. For the estimated number of wells to be drilled at the minimum subscription proceeds of $2 million and the maximum subscription proceeds of $125 million See "Risk Factors - Risks Related to an Investment in a Partnership - Spreading the Risks of Drilling Among a Number of Wells Will be Reduced if Less than the Maximum Subscription Proceeds are Received and Fewer Wells are Drilled." Before the managing general partner selects a prospect on which a well will be drilled by a partnership, it will review all available geologic and production data for wells located in the vicinity of the proposed well including, but not limited to: o various well logs; o completion reports; o plugging reports; and o production reports. 54 For example, production information from surrounding wells in the area is an important indicator in evaluating the economic potential of a proposed well to be drilled. It has been the managing general partner's experience that natural gas production from wells drilled to the formations or the reservoirs in the primary areas is reasonably consistent with nearby wells, although from time to time there can be great differences in the natural gas volumes and performance of wells located on contiguous prospects. However, production information is only one factor and the managing general partner may propose a well to be drilled by a partnership because geologic trends in the immediate area, such as sand thickness, porosities and water saturations, lead the managing general partner to believe that the proposed well locations will be productive. PRIMARY AREAS OF OPERATIONS The managing general partner will not decide on the majority of the specific wells to be drilled in any partnership until the offering of units in that partnership has ended. However, the managing general partner intends that Atlas America Public #14-2004 L.P., which must close on or before December 31, 2004, will drill the prospects described in "Appendix A - Information Regarding Currently Proposed Prospects for Atlas America Public #14-2004 L.P." These prospects represent the wells to be drilled if a portion of the nonbinding targeted subscription proceeds as described in "Terms of the Offering - Subscription to a Partnership" are received. If there are adverse events with respect to any of the currently proposed prospects, the managing general partner will substitute the partnership's prospects as discussed below in "- Interests of Parties." The managing general partner also anticipates that it will designate a portion of the prospects in each partnership designated Atlas America Public #14-2005(_____) L.P. by a supplement or an amendment to the registration statement of which this prospectus is a part. Because only a portion of the prospects for a partnership will be specified, you will not be able to evaluate the majority of the specific prospects that will be drilled by your partnership. However, by waiting as long as possible before selecting all of the specific prospects to be drilled by a partnership, the managing general partner may acquire additional information to help it select better prospects for the partnership, and it may be able to include prospects which were not available when this prospectus was written or even when the offering of units in the partnership was closed. This section includes a general description of the areas where the managing general partner anticipates partnership wells may be drilled. If additional areas are added, then this information will be supplemented. As discussed below, the four primary areas for the partnerships' drilling activities are: o the Mississippian/Upper Devonian Sandstone reservoirs in Fayette and Greene Counties, Pennsylvania; o the Clinton/Medina Geological Formation in western Pennsylvania that also covers an area in eastern Ohio primarily in Stark, Mahoning, Trumbull and Portage Counties; o the Upper Devonian Sandstone Reservoirs in Armstrong County, Pennsylvania; and o the Upper Devonian Sandstone Reservoirs in McKean County, Pennsylvania. Fayette County, Greene County, Armstrong County and McKean County are in western Pennsylvania. The Clinton/Medina geological formation in Pennsylvania and Ohio is the same geological formation, although in Pennsylvania it is often referred to as the Medina/Whirlpool geological formation. For purposes of this prospectus, the term Clinton/Medina geological formation is used for both Ohio and Pennsylvania. The wells drilled to the Clinton/Medina geological formation, regardless of whether they are situated in western Pennsylvania, eastern Ohio, western New York, or southern Ohio, and the Mississippian and/or Upper Devonian Sandstone reservoirs have the following similarities: o 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; o a well drilled to this formation or these reservoirs usually requires hydraulic fracturing of the formation to stimulate productive capacity; 55 o generally, natural gas from a well drilled to this formation or these reservoirs is produced at rates which decline rapidly during the first few years of operations, and although the well can produce for many years, a proportionately larger amount of production can be expected within the first several years; and o it has been the managing general partner's experience that natural gas production from wells drilled to this formation or these reservoirs is reasonably consistent with nearby wells, although from time to time there can be great differences in the natural gas volumes and performance of wells on contiguous prospects. The managing general partner anticipates that the majority of the subscription proceeds of each partnership will be expended in the primary areas, although some of the subscription proceeds of each partnership may be expended in the secondary areas or in areas which are not currently known. In the primary areas, the managing general partner anticipates that more prospects will be drilled in McKean County than the other areas if only the minimum subscription proceeds are received by a partnership, and more prospects will be drilled in Fayette County than the other areas if substantially more than the minimum subscription proceeds are received by a partnership. MISSISSIPPIAN/UPPER DEVONIAN SANDSTONE RESERVOIRS, FAYETTE COUNTY, PENNSYLVANIA. The Mississippian/Upper Devonian Sandstone reservoirs are discontinuous lens-shaped accumulations found throughout most of the Appalachian Basin. These reservoirs have porosities ranging from 5% to 20% with attendant permeabilities. 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. See the geologic evaluation prepared by United Energy Development Consultants, Inc., an independent geological and engineering firm, for a discussion of the development of the Mississippian/Upper Devonian Sandstone reservoirs in Fayette and Greene Counties, Pennsylvania. The wells in the Mississippian/Upper Devonian Sandstone reservoirs will be: o situated on approximately 20 acres, subject to adjustment to take into account lease boundaries; o drilled at least 1,000 feet from a producing well, although a partnership may drill a new well or re-enter an existing well which is closer than 1,000 feet to a plugged and abandoned well; o drilled from approximately 1,900 to 5,500 feet in depth; o classified as natural gas wells which may produce a small amount of oil; and o primarily connected to the gathering system owned by Atlas Pipeline Partners and have their natural gas production primarily marketed to UGI Energy Services as described below in "- Sale of Natural Gas and Oil Production" for the period from November 1, 2004 through March 31, 2006. CLINTON/MEDINA GEOLOGICAL FORMATION IN WESTERN PENNSYLVANIA. 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. Based on the managing general partner's experience, it anticipates that all of the natural gas wells drilled to the Clinton/Medina 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. in "Appendix A - Information Regarding Currently Proposed Prospects for Atlas America Public #14-2004 L.P." for a discussion of the development of the Clinton/Medina Geological Formation in western Pennsylvania, which also covers an area in eastern Ohio primarily in Stark, Mahoning, Trumbull, and Portage Counties. The wells in the Clinton/Medina geological formation in western Pennsylvania and eastern Ohio will be: o primarily situated in Crawford, Mercer, Lawrence, Warren, and Venango Counties, Pennsylvania, and Stark, Mahoning, Trumbull and Portage Counties, Ohio; 56 o situated on approximately 50 acres, subject to adjustment to take into account lease boundaries; o drilled at least 1,650 feet from each other in Pennsylvania, which is greater than the 660 feet minimum distance allowed by state law or local practice to protect against drainage from adjacent wells, and drilled at least 1,000 feet from each other in Ohio; o drilled from approximately 5,100 to 6,300 feet in depth; o classified as natural gas wells which may produce a small amount of oil, although the wells in eastern Ohio may be classified as oil wells; and o primarily connected to the gathering system owned by Atlas Pipeline Partners and have their natural gas production primarily marketed to First Energy Solutions Corporation as described below in " - Sale of Natural Gas and Oil Production". Also, see "- Secondary Areas of Operations" below, for a discussion of the Clinton/Medina geological formation in western New York and southern Ohio. UPPER DEVONIAN SANDSTONE RESERVOIRS, ARMSTRONG COUNTY, PENNSYLVANIA. The Upper Devonian Sandstone reservoirs are discontinuous lens-shaped accumulations found throughout most of the Appalachian Basin. These reservoirs have porosities ranging from greater than 5% to 20% with attendant permeabilities. See the geologic evaluation prepared by United Energy Development Consultants, Inc. for a discussion of the development of the Upper Devonian Sandstone Reservoir in Armstrong County, Pennsylvania. The prospects in Armstrong County, Pennsylvania were acquired from U.S. Energy Exploration Corporation as described below in "- Interests of Parties," and U.S. Energy will participate in the wells with the partnerships. The wells in the Upper Devonian Sandstone reservoirs will be: o situated on approximately 20 acres, subject to adjustment to take into account lease boundaries; o drilled at least 1,000 feet from each other, although under Pennsylvania law in certain circumstances a variance can be obtained, and some of the wells the managing general partner has drilled to date in this general area have been drilled less than 1,000 feet apart, but even in those cases the wells were approximately 980 feet or more from each other; o drilled from approximately 1,800 to 4,400 feet in depth; o classified as natural gas wells which may produce a small amount of oil; and o connected to a gathering system owned by U.S. Energy and have their natural gas production marketed by U.S. Energy as described below in "- Sale of Natural Gas and Oil Production." UPPER DEVONIAN SANDSTONE RESERVOIRS IN MCKEAN COUNTY, PENNSYLVANIA. See "- Upper Devonian Sandstone Reservoirs, Armstrong County, Pennsylvania," above, for a description of these reservoirs and also see the geologic evaluation prepared by United Energy Development Consultants, Inc. for a discussion of the Upper Devonian Sandstone Reservoirs in McKean County, Pennsylvania. Wells located in McKean County and drilled to the Upper Devonian Sandstone reservoirs will be: o situated on approximately 6 acres subject to adjustments to take into account lease boundaries; o drilled from approximately 2,000 to 2,500 feet in depth; o classified as combination wells producing both natural gas and oil; and 57 o connected to the gathering systems owned by Atlas Pipeline Partners and M&M Royalty, LTD. and have their natural gas production primarily marketed to M&M Royalty, LTD. as described below in "- Sale of Natural Gas and Oil Production." SECONDARY AREAS OF OPERATIONS The managing general partner also has reserved the right to use a portion of the subscription proceeds of each partnership to drill development wells in other areas of the Appalachian Basin. The secondary areas anticipated by the managing general partner are discussed below. CLINTON/MEDINA GEOLOGICAL FORMATION IN WESTERN NEW YORK. Wells located in western New York and drilled to the Clinton/Medina geological formation will be: o primarily situated in Chautauqua County; o situated on approximately 40 acres, subject to adjustment to take into account lease boundaries; o drilled from approximately 3,800 to 4,000 feet in depth; o drilled on leases with a net revenue interest of approximately 84.375% to 87.5%; o classified as natural gas wells which may produce a small amount of oil; and o connected to the gathering system owned by Atlas Pipeline Partners and have their natural gas production primarily marketed to First Energy Solutions Corporation as described below, and/or commercial end users in the area, although a portion of the natural gas production may be gathered and marketed by Great Lakes Energy Partners, L.L.C. as described below in " - Sale of Natural Gas and Oil Production." CLINTON/MEDINA GEOLOGICAL FORMATION IN SOUTHERN OHIO. Wells located in southern Ohio and drilled to the Clinton/Medina geological formation will be: o primarily situated in Noble, Washington, Guernsey, and Muskingum Counties; o situated on approximately 40 acres, subject to adjustment to take into account lease boundaries; o drilled at least 1,000 feet from each other; o drilled from approximately 4,900 to 6,500 feet in depth; o drilled on leases with a net revenue interest of approximately 82.5% to 87.5%; o classified as either natural gas wells or oil wells; and o primarily connected to the gathering system owned by Atlas Pipeline Partners if classified as natural gas wells and have their natural gas production primarily marketed by First Energy Solutions Corporation, although a portion of the natural gas production may be gathered and marketed by Triad Energy Corporation of West Virginia, Inc. as described below in "- Sale of Natural Gas and Oil Production." Additionally, the managing general partner anticipates that the leases in southern Ohio will have been originally acquired from a coal company and are subject to a provision that the well must be abandoned if it hinders the development of the coal. Thus, the managing general partner will not drill a well on any lease subject to this provision unless it covers lands that were previously mined. Although this does not totally eliminate the risk because the leases may cover other coal deposits that might be mined during the life of a well, the managing general partner believes that drilling wells on these previously mined leases would be in the best interests of the partnerships. 58 ACQUISITION OF LEASES The managing general partner will have the right, in its sole discretion, to select the prospects which each partnership will drill. The managing general partner intends that Atlas America Public #14-2004 L.P., which must close on or before December 31, 2004, will drill the prospects described in "Appendix A - Information Regarding Currently Proposed Prospects for Atlas America Public #14-2004 L.P." The managing general partner also anticipates that it will designate a portion of the prospects in each partnership designated Atlas America Public #14-2005(_____) L.P. by a supplement or an amendment to the registration statement of which this supplement is a part. The leases covering each prospect on which one well will be drilled will be acquired by a partnership from the managing general partner or its affiliates and credited to the managing general partner as a part of its required capital contribution to the partnership. Neither the managing general partner nor its affiliates will receive any royalty or overriding royalty interest on any well. The managing general partner anticipates that it will select the prospects for each partnership, including any additional and/or substituted prospects, from the following: o leases in its and its affiliates' existing leasehold inventory; o leases that are subsequently acquired by it or its affiliates; or o leases owned by independent third-parties that may participate with the partnership in drilling wells. Most of the prospects acquired by a partnership will be in areas where the managing general partner or its affiliates have previously conducted drilling operations. The managing general partner believes that its and its affiliates' leasehold inventory and leases acquired from third-parties will be sufficient to provide all the prospects to be drilled by each partnership. The managing general partner and its affiliates are continually engaged in acquiring additional leasehold acreage in Pennsylvania, Ohio, and other areas of the United States. As of April 30, 2004, the managing general partner's and its affiliates' undeveloped leasehold acreage was as follows:
UNDEVELOPED LEASE ACREAGE ------------------------- GROSS NET (1) ----- ------- Kentucky..................................................................... 9,710 4,855 Montana...................................................................... 2,650 2,650 New York..................................................................... 37,737 37,737 Ohio......................................................................... 36,552 33,403 Pennsylvania................................................................. 131,483 131,483 West Virginia................................................................ 10,806 5,403 Wyoming...................................................................... 80 80 ------- ------- Total..................................... 229,018 215,561 ======= =======
(1) The net acreage as to which leases expire in fiscal 2004, 2005 and 2006 are as follows: New York: 2006 - 287 acres; Ohio: 2004 - 184 acres, 2005 - 464 acres, 2006 - 96 acres; Pennsylvania: 2004 - 2,867 acres, 2005 - 16,599 acres, 2006 - 25,071 acres. 59 Most, if not all, of the prospects to be selected for the partnerships are expected by the managing general partner to be single well proved undeveloped prospects. Thus, only one well will be drilled on those prospects and the number of prospects the managing general partner will assign to each partnership will be the same as the number of wells which the partnership has the funds to drill. This also means that the partnership, in all likelihood, will not farmout any acreage associated with those prospects. However, the need for a farmout might arise, for example, if during drilling or subsequently the managing general partner determines there might be a productive horizon situated above (i.e. uphole) the target horizon, but the partnership does not have the funds to complete the well in the horizon or the completion of the horizon would be inconsistent with the partnership's objectives. In this event, the managing general partner might determine to farmout the activity for the partnership. Generally, a farmout is an agreement in which the owner of the lease or existing well agrees to assign its interest in certain acreage under the lease or the existing well to an assignee subject to the assignee drilling one or more wells or completing or recompleting the existing well in one or more horizons. The owner would retain some interest in the assigned acreage or well. See "Conflicts of Interest - Conflicts Involving the Acquisition of Leases" for the procedure for a farmout, and "Material Federal Income Tax Consequences - Farmouts." DEEP DRILLING RIGHTS RETAINED BY MANAGING GENERAL PARTNER. In the areas where the Clinton/Medina is the primary geological formation, the lease assignments to each partnership will be limited to a depth of from the surface to the top of the Queenston geological formation, and the managing general partner will retain the deeper drilling rights beginning with the Queenston geological formation. In all other areas the lease assignments to each 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 deeper drilling rights including ownership of any coal bed methane production that might be obtained from the deeper formations. Conversely, as between a partnership and the managing general partner, the partnership will own any coal bed methane production that might be obtained from the shallower formations that are not included in the deeper drilling rights retained by the managing general partner. The amount of the credit the managing general partner receives for the leases it contributes to a partnership does not include any value allocable to the deeper drilling rights retained by it. If in the future the managing general partner undertakes any activities with respect to the deeper formations, then the partnerships would not share in the profits from these activities, nor would they pay any of the associated costs. INTERESTS OF PARTIES Generally, production and revenues from a well drilled by a partnership will be net of the applicable landowner's royalty interest, which is typically 1/8th (12.5%) of gross production, and any interest in favor of third-parties such as an overriding royalty interest. Landowner's royalty interest generally means an interest that is created in favor of the landowner when an oil and gas lease is obtained; and overriding royalty interest generally means an interest that is created in favor of someone other than the landowner. In either case, the owner of the interest receives a specific percentage of the natural gas and oil production free and clear of all costs of development, operation, or maintenance of the well. This is compared with a working interest, which generally means an interest in the lease under which the owner of the interest must pay some portion of the cost of development, operation, or maintenance of the well. Also, the leases will be subject to terms that are customary in the industry such as free gas to the landowner-lessor for home heating requirements, etc. The managing general partner anticipates that each partnership generally will have a net revenue interest in its leases in its primary drilling areas as set forth in the chart 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 chart expresses the percentage of production revenues that the managing general partner, the landowner, other third-parties, and you and the other investors in a partnership will share in from the wells in three of the four primary proposed areas. The fourth primary proposed area in Armstrong County, Pennsylvania is discussed following the chart. The chart assumes that the partnership owns 100% of the working interest in the well. If a partnership acquires a lesser percentage working interest in a well, which will be the case for all of the proposed wells situated in Armstrong County, for example, then the partnership's net revenue interest in that well will decrease proportionately. The actual number, identity and percentage of working interests or other interests in prospects to be acquired by the partnerships will depend on, among other things: o the amount of subscription proceeds received in a partnership; o the latest geological and production data; 60 o potential title or spacing problems; o availability and price of drilling services, tubular goods and services; o approvals by federal and state departments or agencies; o agreements with other working interest owners in the prospects; o farmins and farmouts; and o continuing review of other prospects that may be available. PRIMARY AREAS. CLINTON/MEDINA GEOLOGICAL FORMATION IN WESTERN PENNSYLVANIA AND MISSISSIPPIAN/UPPER DEVONIAN SANDSTONE RESERVOIRS IN FAYETTE AND GREENE COUNTIES, PENNSYLVANIA AND UPPER DEVONIAN SANDSTONE RESERVOIRS IN MCKEAN COUNTY, PENNSYLVANIA.
PARTNERSHIP THIRD PARTY 87.5% PARTNERSHIP ENTITY INTEREST ROYALTY INTEREST NET REVENUE INTEREST (2) - ------ -------------- ------------------ ------------------------ Managing General Partner.................32% partnership interest (1) 28.0% Investors................................68% partnership interest (1) 59.5% Third Party..........................................................12.5% Landowner Royalty Interest 12.5% ------ 100.0% ======
- ------------- (1) These percentages are for illustration purposes only and assume the managing general partner's minimum required capital contribution to each partnership of 25% and capital contributions of 75% from you and the other investors. The actual percentages are likely to be different because they will be based on the actual capital contributions of the managing general partner and you and the other investors. However, the managing general partner's total revenue share may not exceed 35% of partnership revenues regardless of the amount of its capital contributions. (2) It is possible that the wells could have a net revenue interest to a partnership as low as 84.375% which would reduce the investors' interest to 57.375%. UPPER DEVONIAN SANDSTONE RESERVOIRS IN ARMSTRONG COUNTY, PENNSYLVANIA. The managing general partner anticipates the leases in Armstrong County, Pennsylvania will have a net revenue interest to a partnership of 84.375% which would reduce the investors' net revenue interest in the above chart to 57.375% assuming a 100% working interest. U.S. Energy, the originator of the leases, however, will retain a 25% working interest in the wells and participate with the partnership in the costs of drilling, completing, and operating the wells to the extent of its retained working interest. Thus, the net revenue interest to the investors will be reduced to approximately 43% which is 75% of 57.375%. SECONDARY AREAS. Although the managing general partner anticipates that each 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 that a partnership is required to own before drilling a well in other areas of the United States. The leases in these other areas may be subject to interests in favor of third-parties that are not currently known such as: o overriding royalty interests; o net profits interests; o carried interests; o production payments; 61 o reversionary interests pursuant to farmouts or non-consent elections under joint operating agreements; or o other retained or carried interests. TITLE TO PROPERTIES Title to all leases acquired by a 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: o the managing general partner; o the operator; o their affiliates; or o any nominee designated by the managing general partner. Title to each partnership's leases will be transferred to the partnership and filed for record from time to time after the wells are drilled and completed. The managing general partner will take the steps it deems necessary to assure that each partnership has acceptable title for its purposes. However, it is not the practice in the natural gas and oil industry to warrant title or obtain title insurance on leases and the managing general partner will provide neither for the leases it assigns to a partnership. The managing general partner will obtain a favorable formal title opinion for the leases before each well is drilled, but will not obtain a division order title opinion after the well is completed. The managing general partner may use its own judgment in waiving title requirements and will not be liable for any failure of title of leases transferred to a partnership. Also, there is no assurance that the partnerships will not experience losses from title defects excluded from or not disclosed by the formal title opinion or that would have been disclosed by a division order title opinion. Although past performance is no guarantee of future results, as of September 30, 2003 the previous partnerships sponsored by the managing general partner and its affiliates have participated in drilling more than 1,991 wells in the Appalachian Basin since 1985, and none of the wells have been lost because of title failure. (See "Prior Activities.") DRILLING AND COMPLETION ACTIVITIES; OPERATION OF PRODUCING WELLS The managing general partner intends that Atlas America Public #14-2004 L.P., which must close on or before December 31, 2004, will drill the prospects described in "Appendix A - Information Regarding Currently Proposed Prospects for Atlas America Public #14-2004 L.P." These prospects represent a portion of the wells to be drilled if the nonbinding targeted subscription proceeds described in "Terms of the Offering - Subscription to a Partnership" are received. The managing general partner also anticipates that it will designate a portion of the prospects in each partnership designated Atlas America Public #14-2005(_____) L.P. by a supplement or an amendment to the registration statement of which this prospectus is a part. On receipt of the minimum subscription proceeds the managing general partner on behalf of a partnership may break escrow, transfer the escrowed funds to a partnership account, enter into the drilling and operating agreement, which is attached to the partnership agreement as Exhibit II, with itself or an affiliate as operator, and begin drilling to the extent the prospects have been identified in this prospectus or in a supplement or an amendment to the registration statement. Under the drilling and operating agreement, the responsibility for drilling and either completing or plugging partnership wells will be on the managing general partner or an affiliate as the operator and the general drilling contractor. Under the drilling and operating agreement, each partnership is required to prepay the investors' share of the drilling and completion costs of its wells to the managing general partner as the operator. If one or more of a partnership's wells will be drilled in the calendar year after the year in which the advance payment is made, the required advance payment allows the partnership to secure tax benefits of prepaid intangible drilling costs based on a substantial business purpose for the advance payment under the drilling and operating agreement. The managing general partner as operator and general drilling contractor will begin drilling the wells no later than March 31, 2005 for Atlas America Public #14-2004 L.P., and March 31, 2006 Atlas America Public #14-2005(B) L.P. (See "Material Federal Income Tax Consequences-Drilling Contracts.") 62 During drilling operations the managing general partner's duties as operator and general drilling contractor will include: o making the necessary arrangements for drilling and completing partnership wells and related facilities for which it has responsibility under the drilling and operating agreement; o managing and conducting all field operations in connection with drilling, testing, and equipping the wells; and o making the technical decisions required in drilling and completing the wells. All partnership wells will be drilled to a sufficient depth to test thoroughly the objective geological formation. Under the drilling and operating agreement the managing general partner, as operator and general drilling contractor, will complete each well if there is a reasonable probability of obtaining commercial quantities of natural gas or oil. However, based on its past experience, the managing general partner anticipates that most of the development wells drilled in the primary and secondary areas will have to be completed before it can determine the well's productivity. If the managing general partner, as operator and general drilling contractor, determines that a well should not be completed, then the well will be plugged and abandoned. During producing operations the managing general partner's duties, as operator, will include: o managing and conducting all field operations in connection with operating and producing the wells; o making the technical decisions required in operating the wells; and o maintaining the wells, equipment, and facilities in good working order during their useful life. The managing general partner, as operator, will be reimbursed for its direct expenses and will receive well supervision fees at competitive rates for operating and maintaining the wells during producing operations. As discussed in "Summary of Drilling and Operating Agreement," the drilling and operating agreement contains a number of other material provisions which you are urged to review. Certain wells may be drilled with third-parties owning a portion of the working interest in the wells. Any other working interest owner in a well may have a separate agreement with the managing general partner for drilling and operating the well with differing terms and conditions from those contained in a partnership's drilling and operating agreement. SALE OF NATURAL GAS AND OIL PRODUCTION POLICY OF TREATING ALL WELLS EQUALLY IN A GEOGRAPHIC AREA. The managing general partner is responsible for selling each partnership's natural 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 partnerships, concerning to whom and at what price the natural gas and oil will be sold. For example, the managing general partner calculates a weighted average selling price for all of the natural gas sold in the geographic area by dividing the money received from the sale of all of the natural gas sold to customers in the area, which may be at different prices, by the volume of all natural gas sold from the wells in the area. For natural gas sold in western Pennsylvania the managing general partner received an average selling price after deducting all expenses, including transportation expenses, of approximately: o $2.35 per mcf, which means 1,000 cubic feet of natural gas, in 1999; o $3.30 per mcf in 2000; o $4.08 per mcf in 2001; o $3.34 per mcf in 2002; and 63 o $4.78 per mcf in 2003. These prices were after the effects of hedging. If all the natural gas produced cannot be sold because of limited gathering line or pipeline capacity, or limited demand for the natural gas, which increases pipeline pressure, then the production that is sold will be from those wells which have the greatest well pressure and are able to feed into the pipeline, regardless of which partnerships own the wells. The proceeds from these natural gas sales will be credited only to the partnerships whose wells produced the natural gas sold. GATHERING OF NATURAL GAS. Under the partnership agreement the managing general partner will be responsible for gathering and transporting the natural gas produced by the partnerships to interstate pipeline systems, local distribution companies, and/or end-users in the area. For the majority of each partnership's natural gas production, including natural gas in the primary areas, as discussed below, the managing general partner anticipates that it will use the gathering system owned by Atlas Pipeline Partners, L.P. (and Atlas Pipeline Operating Partnership) which is a master limited partnership formed by a subsidiary of Atlas America as managing general partner using Atlas America and Viking Resources personnel who act as its officers and employees. Atlas Pipeline Partners acquired the natural gas gathering system and related facilities of Atlas America, Resource Energy, and Viking Resources in February 2000. At December 31, 2003, the gathering system consists of approximately 1,380 miles of intrastate pipelines located in western Pennsylvania, eastern Ohio, and western New York. If a partnership's natural gas is not transported through the Atlas Pipeline Partners gathering system, it is because there is a third-party operator or the gathering system has not been extended to the wells. In these cases, which includes the McKean County area as described in "Compensation - Gathering Fees," the natural gas will be transported through a third-party gathering system, and the partnership will pay the managing general partner a competitive gathering fee, all or a portion of which will be paid by it to the third-party. As a part of the sale of the gathering system to Atlas Pipeline Partners in February 2000, Atlas America and its affiliates, Resource Energy and Viking Resources, made the commitments set forth below which to varying degrees may affect the partnerships. 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. Atlas America, Resource Energy and Viking Resources are required to pay a gathering fee to Atlas Pipeline Partners equal to the greater of $0.35 per mcf or 16% of the gross sales price for each mcf transported through the gathering system of Atlas Pipeline Partners. If a partnership pays a lesser amount, which is anticipated by the managing general partner to range from $.29 per mcf to $.35 per mcf except in the McKean County area as described in "Compensation - Gathering Fees," then Atlas America, Resource Energy or Viking Resources must pay the difference to Atlas Pipeline Partners. Also, Atlas America, Resource Energy and Viking Resources committed to adding 225 wells to the gathering system over a period from January 1, 1999, until December 31, 2002, which included any well drilled in a partnership sponsored by them, which has been satisfied. The wells had to be drilled within 2,500 feet of the gathering system and the partnership as the well owner had to construct up to 2,500 feet of small diameter sales or flow lines from the wellhead to the gathering system. Finally, Atlas America, Resource Energy and Viking Resources agreed to assist Atlas Pipeline Partners in identifying existing gathering systems for possible acquisition and Atlas America 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. NATURAL GAS CONTRACTS. Initially, the majority of each partnership's natural gas production will be sold to two different natural gas purchasers, First Energy Solutions Corporation and UGI Energy Services, Inc., as described below. The agreement with First Energy Solutions Corporation, which is the marketing affiliate of First Energy Corporation, which is based in Akron, Ohio and is a large regional electric utility listed on the New York Stock Exchange and trading under the symbol (FE), is an agreement among the managing general partner, Resource Energy and Atlas Energy Group, Inc. for a 10-year term which began on April 1, 1999. Subject to certain exceptions set forth below, First Energy Solutions Corporation has a last right of refusal to buy all of the natural gas produced and delivered by the managing general partner and its affiliates, which includes the partnerships, at certain delivery points with the facilities of: 64 o East Ohio Gas Company, National Fuel Gas Distribution, Columbia of Ohio, and Peoples Natural Gas Company, which are local distribution companies; and o National Fuel Gas Supply, Columbia Gas Transmission Corporation, Tennessee Gas Pipeline Company, and Texas Eastern Transmission Company, which are interstate pipelines. The agreement with First Energy Solutions Corporation requires the parties to negotiate a new pricing arrangement at each delivery point for subsequent contract periods which is usually one year. If, at the end of any applicable period, the parties cannot agree to a new price for any delivery point, then the managing general partner and its affiliates may solicit offers from third-parties to buy the natural gas for that delivery point. If First Energy Solutions Corporation does not match this price, then the natural gas may be sold to the third-party. This process is repeated at the end of each contract period. The agreement with First Energy Solutions Corporation may be suspended for force majeure, which means generally such things as an act of God, but also includes the permanent closing of the factories of Carbide Graphite or Duferco Farrell Corporation during the term of First Energy Solutions Corporation's agreements to sell natural gas to them. If these factories were closed, however, the managing general partner believes that First Energy Solutions Corporation would be able to find alternative purchasers and would not invoke the force majeure. The managing general partner agreed to a new pricing arrangement with First Energy Solutions Corporation which is effective through March 2006. First Energy Corporation has provided a guaranty of the monetary obligations of First Energy Solutions Corporation of an amount up to $15 million for a period until March 31, 2005, which will continue on a monthly basis thereafter unless terminated on 30 days notice. As of January 1, 2004, this guaranty would cover natural gas sales of all the managing general partner's partnerships for approximately 85 days of sales. The majority of the managing general partner's and its affiliates' natural gas is subject to the agreement with First Energy Solutions Corporation, with the following exceptions: o natural gas sold through interconnects established after the agreement with First Energy Solutions Corporation which includes the majority of the natural gas produced from wells in Fayette County; o natural gas being sold to Warren Consolidated, an industrial end-user, and direct delivery customer of the managing general partner and its affiliates; o natural gas that at the time of the agreement was already dedicated for the life of the well to another buyer; o natural gas that is produced by a company which was not an affiliate of the managing general partner at the time of the agreement; o natural gas that is delivered to interstate pipelines or local distribution companies other than those described above; or o natural gas that is produced from well(s) operated by a third-party or subject to an agreement under which a third-party was to arrange for the gathering and sale of the natural gas. As of June 14, 2004 the managing general partner and its affiliates, including its prior affiliated partnerships, were selling approximately 52.4% of their natural gas production under the agreement with First Energy Solutions Corporation. However, as set forth in "- Primary Areas of Operations" above, the managing general partner anticipates that more prospects will be drilled in Fayette County than the other areas if substantially more than the minimum subscriptions are received by a partnership, and the majority, if not all, of the natural gas in Fayette County will be sold to UGI Energy Services until March 31, 2006. Also, the natural gas produced from Armstrong County will be sold to U.S. Energy Exploration Corporation and the natural gas produced from McKean County will be sold to M&M Royalty Ltd. The managing general partner anticipates that the remainder of the natural gas produced by each partnership from wells drilled in the primary and secondary areas will be sold to First Energy Solutions Corporation. See "Appendix A - Information Regarding Currently Proposed Prospects for Atlas America Public #14-2004 L.P." 65 The pricing arrangements with First Energy Solutions Corporation, UGI Energy Services, U.S. Energy Exploration Corporation, M&M Royalty Ltd. and the other third-parties are tied to the New York Mercantile Exchange Commission ("NYMEX") monthly futures contracts price, which is reported daily in the Wall Street Journal. The total price received for each partnership's gas is a combination of the monthly NYMEX futures price plus a fixed basis. For example, the NYMEX futures price is the base price and there is an additional premium paid because of the location of the gas (the Appalachian Basin) in relation to the gas market which is referred to as the basis. The premium over quoted prices on the NYMEX received by the managing general partner and its affiliates has ranged between $0.33 to $0.46 per Mcf during the past three fiscal years. See "- Policy of Treating All Wells Equally in a Geographic Area" for the average natural gas prices since 1999. Pricing for natural gas and oil has been volatile and unpredictable for many years. To limit the managing general partner's and its partnerships' exposure to changes in natural gas prices the managing general partner uses hedges through its natural gas purchasers as described below, and through contracts including regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The futures contracts employed by the managing general partner are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to 24 months in the future. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, the managing general partner has established a committee to assure that all financial trading is done in compliance with the managing general partner's hedging policies and procedures. The managing general partner does not intend to contract for positions that it cannot offset with actual production. First Energy Solutions Corporation, UGI Energy Services and other third-party marketers also use NYMEX based financial instruments to hedge their pricing exposure and make price hedging opportunities available to the managing general partner. As of June 14, 2004, the majority of the managing general partner's hedges are implemented through the natural gas purchasers. These transactions are similar to NYMEX based futures contracts, swaps and options, but also require firm delivery of the hedged quantity. Thus, the managing general partner limits these arrangements to much smaller quantities than those projected to be available at any delivery point. The price paid by First Energy Solutions Corporation, UGI Energy Services, and any other third-party marketers for certain volumes of natural gas sold under these hedge agreements may be significantly different from the underlying monthly spot market value. The portion of natural gas that is hedged and the manner in which it is hedged (e.g. fixed pricing, floor and/or costless collar pricing, which is a floor price with a cap, etc.) changes from time to time. As of June 14, 2004, the managing general partner's overall price hedging position for the future months ending December 31, 2004 was approximately as follows: o 51.2% was hedged with a fixed price; o 13.3% was hedged with a floor price and/or costless collar price; and o 35.5% was not hedged and was subject to market based pricing. Approximately 49.6% of these hedges were implemented through First Energy Solutions Corporation and 15.8% were implemented through UGI Energy Services. It is difficult to project what portion of these hedges will be allocated to each partnership by the managing general partner because of uncertainty about the quantity, timing, and delivery locations of natural gas that may be produced by a partnership. Although hedging provides the partnerships some protection against falling prices, these activities also could reduce the potential benefits of price increases. MARKETING OF NATURAL GAS PRODUCTION FROM WELLS IN OTHER AREAS OF THE UNITED STATES. The managing general partner expects that natural gas produced from wells drilled in areas of the Appalachian Basin other than described above, will be primarily tied to the spot market price and supplied to: 66 o gas marketers; o local distribution companies; o industrial or other end-users; and/or o companies generating electricity. 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. Unlike natural gas, crude oil does not present any transportation problem. The managing general partner anticipates selling any oil produced by the wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil in spot sales. The managing general partner was receiving an average selling price for oil of approximately: o $16.20 per barrel in 1999; o $26.21 per barrel in 2000; o $22.60 per barrel in 2001; o $18.92 per barrel in 2002; and o $29.06 per barrel in 2003. During the term of the partnerships it is anticipated that the price of oil will be uncertain and volatile. INSURANCE Since 1972 the managing general partner and its affiliates, including its partnerships, have been involved in the drilling of approximately 5,300 wells, most of which were developmental wells, in Ohio, Pennsylvania, and other areas of the Appalachian Basin. They have made only one material insurance claim when in February 2003 one of the wells in another investment partnership incurred an uncontrolled flow of natural gas and oil with a fire during drilling which was subsequently controlled, but resulted in the loss of a subcontractor's drilling rig and third-party claims. As of June 16, 2004, the managing general partner's insurance carrier has paid approximately $1,233,000 for property damage claims to third-parties and additional claims have been submitted which have not yet been paid. The managing general partner's insurance company is exploring all avenues for subrogation. See "Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners - Insurance" for a discussion of the insurance coverage. USE OF CONSULTANTS AND SUBCONTRACTORS The partnership agreement authorizes the managing general partner to use the services of independent outside consultants and subcontractors on behalf of the partnerships. The services will normally be paid on a per diem or other cash fee basis and will be charged to the partnership on whose behalf the costs were incurred 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. COMPETITION, MARKETS AND REGULATION NATURAL GAS REGULATION Governmental agencies regulate the production and transportation of natural gas. Generally, the regulatory agency in the state where a producing natural gas well is located supervises production activities and the transportation of natural gas sold into intrastate markets, and the Federal Energy Regulatory Commission ("FERC") regulates the interstate transportation of natural gas. 67 Natural gas prices have not been regulated since 1993, and the price of natural gas is subject to the supply and demand for the natural gas along with factors such as the natural gas' BTU content and where the wells are located. Since 1985 FERC has sought to promote greater competition in natural gas markets in the United States. Traditionally, natural gas was sold by producers to interstate pipeline companies which served as wholesalers that resold the natural gas to local distribution companies for resale to end-users. FERC changed this market structure by requiring interstate pipeline companies to transport natural gas for third-parties. In 1992 FERC issued Order 636 and a series of related orders which required pipeline companies to, among other things, separate their sales services from their transportation services and provide an open access transportation service that is comparable in quality for all natural gas producers or suppliers. The premise behind FERC Order 636 was that the interstate pipeline companies had an unfair advantage over other natural gas producers or suppliers because they could bundle their sales and transportation services together. FERC Order 636 is designed to ensure that no natural gas seller has a competitive advantage over another natural gas seller because it also provides transportation services. In 2000 FERC issued Order 637 and subsequent orders to enhance competition by removing price ceilings on short-term capacity release transactions. It also enacted other regulatory policies that are intended to enhance competition in the natural gas market and increase the flexibility of interstate natural gas transportation. FERC has further required pipeline companies to develop electronic bulletin boards to provide standardized access to information concerning capacity and prices. CRUDE OIL REGULATION Oil prices are not regulated, and the price is subject to the supply and demand for oil, along with qualitative factors such as the gravity of the crude oil and sulfur content differentials. COMPETITION AND MARKETS There are many companies engaged in natural gas and oil drilling operations in the Appalachian Basin, where all or most of the wells in each partnership will be located. According to the Energy Information Administration, the independent statistical and analytical agency within the Department of Energy, in 2002 there were 23 TCF (a "TCF" means one trillion cubic feet of natural gas) of natural gas consumed in the United States which represented approximately 23.6% of the total energy used. The Appalachian Basin accounted for approximately 3.4% of the total domestic natural gas production in the year 2002 in the United States. Also, according to the Natural Gas Annual 2002, an annual report published by the Energy Information Administration Office of Oil and Gas, as of December 31, 2002, the Appalachian Basin's economically recoverable reserves represented approximately 5.7% of total domestic reserves. Further, World Oil magazine predicted in its February 2004 issue that approximately 5,576 oil and gas wells will be drilled in the Appalachian Basin during 2004, representing approximately 16.7% of the total number of wells it predicted will be drilled in the United States during 2004. This is an increase of 12.8% over the number of Appalachian wells to have been drilled during 2003 compared to an increase of 9.7% in the total wells to have been drilled in the United States from 2003 to 2004. The oil and gas industry is highly competitive in all phases, including acquiring suitable leases to drill and marketing natural gas and oil production from the wells. Product availability and price are the principal means of competing in selling natural gas and oil. Many of the partnerships' competitors will have financial resources and staffs larger than those available to the partnerships. This may enable them to identify and acquire desirable leases and market their natural gas and oil production more effectively than the managing general partner and the partnerships. While it is impossible to accurately determine the partnerships' industry position, the managing general partner does not consider the partnerships' operations to be a significant factor in the industry. Current economic conditions indicate that the costs of exploration and development are increasing gradually. However, the natural gas and oil industry has from time to time experienced periods of rapid cost increases. Over the term of a partnership there may be fluctuating or increasing costs in doing business which directly affect the managing general partner's ability to operate the partnership's wells at acceptable price levels. Also, the natural gas and oil price increases which have occurred from time to time may increase the demand for drilling rigs and other related equipment. This may increase the cost to drill the wells, which are drilled for the partnerships on a cost plus 15% basis, or reduce the availability of drilling rigs and related equipment, both of which could adversely affect the partnerships. In this regard, the cost of a partnership well has increased recently because the cost of tubular steel has increased as a result of rising steel prices. 68 The natural gas and oil produced by your partnership's wells must be marketed for you to receive revenues. During the fiscal years ending 2003, 2002 and 2001, the managing general partner did not experience any problems in selling natural gas and oil, although the prices varied significantly during those periods. As set forth above, natural gas and oil prices are not regulated, but instead are subject to factors which are generally beyond the partnership's control such as the supply and demand for the natural gas and oil. For example, reduced natural gas demand and/or excess natural gas supplies will result in lower prices. Other factors affecting the price and/or marketing of natural gas and oil production, which are also beyond the control of the partnerships and cannot be accurately predicted, are the following: o the proximity, availability, and capacity of pipeline and other transportation facilities; o competition from other energy sources such as coal and nuclear energy; o competition from alternative fuels when large consumers of natural gas are able to convert to alternative fuel use systems; o local, state, and federal regulations regarding production and transportation; o the general level of market demand for natural gas and oil on a regional, national and worldwide basis; o fluctuating seasonal supply and demand for natural gas and oil because of various factors such as home heating requirements in the winter months; o political instability and/or war in natural gas and oil producing countries; o the amount of domestic production of natural gas and oil; and o the amount of foreign imports of natural gas and oil, including liquid natural gas from Canada which the managing general partner believes becomes economic when natural gas prices are at or above $3.50 per mcf, and the actions of the members of the Organization of Petroleum Exporting Countries ("OPEC") which include production quotas for petroleum products from time to time with the intent of increasing, maintaining, or decreasing price levels. For example, the North American Free Trade Agreement ("NAFTA") eliminated trade and investment barriers in the United States, Canada, and Mexico, and from time to time there have been increased imports into the United States of Canadian natural gas. Without a corresponding increase in demand in the United States, the imported natural gas would have an adverse effect on both the price and volume of natural gas sales from the partnerships' wells. The managing general partner is unable to predict what effect the various factors set forth above will have on the future price of the natural gas and oil sold from the partnerships' wells. However, according to the Energy Information Administration, the use of natural gas in the United States is projected to increase approximately 51% to 69% between 1999 and 2020, and there have been several developments which the managing general partner believes have the effect of increasing the demand for natural gas. For example, the Clean Air Act Amendments of 1990 contain incentives for the future development of "clean alternative fuel," which includes natural gas and liquefied petroleum gas for "clean-fuel vehicles." Also, the accelerating deregulation of electricity transmission has caused a convergence between the natural gas and electricity industries. In 2003, according to information from the Energy Information Administration, the breakout of energy sources for the generation of electricity in the United States was as follows: o natural gas fired power plants were used to produce approximately 15%; o coal-fired power plants were used to produce approximately 53%; 69 o nuclear power plants were used to produce approximately 21%; and o large scale hydroelectric projects were used to produce approximately 7%. In recent years, the electricity industry has increased its reliance on natural gas because of increased competition in the electricity industry and the enforcement of stringent environmental regulations, and according to the Energy Information Administration, the demand for natural gas by producers of electricity is expected to increase through the decade. For example, the Environmental Protection Agency has sought to enforce environmental regulations which increase the cost of operating coal-fired power plants. Also, the last nuclear power plant to come online in the United States was in June 1996, although the existing nuclear power plants have increased their capacity. Thus, the managing general partner believes that natural gas is becoming the fuel of choice for electricity producers since they have started moving away from dirtier-burning fuels, such as coal and oil and no nuclear power plants have come online since 1996. Also, some of the new natural gas fired power plants which are coming into service are not designed to allow for switching to other fuels. STATE REGULATIONS Oil and gas operations are regulated in Pennsylvania by the Department of Environmental Resources. Pennsylvania and the other states where each partnership's wells may be situated impose a comprehensive statutory and regulatory scheme for natural gas and oil operations, including supervising the production activities and the transportation of natural gas sold in intrastate markets, which creates additional financial and operational burdens. Among other things, these regulations involve: o new well permit and well registration requirements, procedures, and fees; o landowner notification requirements; o certain bonding or other security measures; o minimum well spacing requirements; o restrictions on well locations and underground gas storage; o certain well site restoration, groundwater protection, and safety measures; o discharge permits for drilling operations; o various reporting requirements; and o well plugging standards and procedures. These state regulatory agencies also have broad regulatory and enforcement powers including those associated with pollution and environmental control laws, which are discussed below. ENVIRONMENTAL REGULATION Each partnership's drilling and producing operations are subject to various federal, state, and local laws covering the discharge of materials into the environment, or otherwise relating to the protection of the environment. The Environmental Protection Agency and state and local agencies will require the partnerships to obtain permits and take other measures with respect to: o the discharge of pollutants into navigable waters; o disposal of wastewater; and o air pollutant emissions. 70 If these requirements or permits are violated there can be substantial civil and criminal penalties which will increase if there was willful negligence or misconduct. Also, the partnerships may be subject to fines, penalties and unlimited liability for cleanup costs under various federal laws such as the Federal Clean Water Act, the Clean Air Act, the Resource Conservation and Recovery Act, the Oil Pollution Act of 1990, the Toxic Substance Control Act and the Comprehensive Environmental Response, Compensation and Liability Act of 1980 for oil and/or hazardous substance contamination or other pollution caused by the drilling activities or the well and its production. Also, a partnership's liability can extend to pollution costs that occurred on the leases before they were acquired by the partnership. Although the managing general partner will not transfer any lease to a 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 a partnership. Thus, there is a risk that the leases will have potential environmental liability even before drilling begins. A partnership's required compliance with these environmental laws and regulations may cause delays or increase the cost of the partnership's drilling and producing activities. Because these laws and regulations are frequently changed, the managing general partner is unable to predict the ultimate costs of complying with present and future environmental laws and regulations. Also, the managing general partner is unable to obtain insurance to protect against many environmental claims. PROPOSED REGULATION From time to time there are a number of proposals considered in Congress and in the legislatures and agencies of various states that if enacted would significantly and adversely affect the natural gas and oil industry and the partnerships. The proposals involve, among other things: o limiting the disposal of waste water from wells, which could substantially increase a partnership's operating costs and make the partnership's wells uneconomical to produce; and o changes in the tax laws as discussed in "Material Federal Income Tax Consequences-Changes in the Law." Also, Congress could re-enact price controls in the future. However, it is impossible to accurately predict what proposals, if any, will be enacted and their subsequent effect on a 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. Each partnership will be a separate business entity from the other partnerships, and you will be a partner only in the partnership in which you invest. You will have no interest in the business, assets, or tax benefits of the other partnerships unless you also invest in the other partnerships. Thus, your investment return will depend solely on the operations and success or lack of success of the particular partnership in which you invest. COSTS 1. ORGANIZATION AND OFFERING COSTS. Organization and offering costs will be charged 100% to the managing general partner. However, the managing general partner will not receive any credit towards its required capital contribution or its revenue share for any organization and offering costs charged to it in excess of 15% of a partnership's investors' subscription proceeds. o Organization and offering costs generally means all costs of organizing and selling the offering and includes the dealer-manager fee, sales commissions, the up to .5% reimbursement for bona fide accountable due diligence expenses, and the .5% accountable reimbursement for permissible non-cash compensation. 71 The managing general partner will pay a portion of the organization and offering costs to itself, its affiliates and third-parties and it will contribute the remainder to the partnership in the form of services related to organizing this offering. The managing general partner will receive a credit for these payments and services towards its required capital contribution in each partnership. The managing general partner's credit for its contribution of services for organization costs will be determined based on generally accepted accounting principles. The definition of organization and offering costs is set forth in the partnership agreement. 2. LEASE COSTS. Each partnership's leases will be contributed by the managing general partner. The managing general partner will be credited with a capital contribution for each lease valued at: o its cost; or o fair market value if the managing general partner has reason to believe that cost is materially more than fair market value. 3. INTANGIBLE DRILLING COSTS. Intangible drilling costs of your partnership will be charged 100% to you and the other investors. o Intangible drilling costs generally means those costs of drilling and completing a well that are currently deductible, as compared with lease costs, which must be recovered through the depletion allowance, and equipment costs, which must be recovered through depreciation deductions. Although subscription proceeds of a partnership may be used to pay the costs of drilling different wells depending on when the subscriptions are received, not less than 90% of the subscription proceeds of you and the other investors will be used to pay intangible drilling costs regardless of when you subscribe. Also, even if the IRS successfully challenged the managing general partner's characterization of a portion of these costs as deductible intangible drilling costs, and instead recharacterized the costs as some other item that may be non-deductible, such as equipment costs and/or lease costs, this recharacterization by the IRS would have no effect on the allocation and payment of the costs by you and the other investors under the partnership agreement. 4. EQUIPMENT COSTS. Equipment costs of your partnership will be charged 66% to the managing general partner and 34% to you and the other investors. However, if the total equipment costs for your partnership's wells that would be charged to you and the other investors exceeds an amount equal to 10% of the subscription proceeds of you and the other investors in the partnership, then the excess will be charged to the managing general partner. See the discussion of equipment costs in 5, below. o Equipment costs generally means the costs of drilling and completing a well that are not currently deductible and are not lease costs. 5. OPERATING COSTS, DIRECT COSTS, ADMINISTRATIVE COSTS AND ALL OTHER COSTS. Operating costs, direct costs, administrative costs, and all other partnership costs of your partnership not specifically charged will be charged to the parties in the same ratio as the related production revenues are being credited. o These costs generally include all costs of partnership administration and producing and maintaining the partnership's wells. Each well in a partnership will have a different productive life and as a well becomes uneconomic to produce it will be plugged and abandoned. The costs of plugging and abandoning a well (other than those incurred in connection with the drilling of a nonproductive well) are shared between the managing general partner and you and the other investors in the same percentage as the related production revenues are being shared. For example, if the investors are receiving 68% of the partnership revenues 72 and the managing general partner is receiving 32% of the partnership revenues, then the cost of plugging and abandoning the wells will be shared in the same percentages. Typically, the managing general partner will apply the salvage value of the equipment, which generally is shared 66% by the managing general partner and 34% by you and the other investors, towards this obligation. These sharing percentages, however, may vary to a small degree as discussed in 4, above, depending on the total equipment costs for your partnerships wells compared to 10% of the subscription proceeds of you and the other investors in the partnership. See "Compensation - Drilling Contracts," for a discussion of the partnerships' equipment costs estimated by the managing general partner for an average well in the primary drilling areas. To cover any shortfall for you and the other investors between your share of the equipment proceeds and your share of the plugging and abandoning costs of the well, the managing general partner has the right beginning one year after a partnership well begins producing to retain up to $200 per month to cover future plugging and abandonment costs of the well. This $200 also includes a proportionate share of the managing general partner's share of partnership revenues, which will be used exclusively for the managing general partner's share of the plugging and abandonment costs of the well. To the extent any portion of the reserve ultimately is not needed for the plugging and abandonment costs of the well, then it will be returned to the general operating revenues of the partnership. 6. THE MANAGING GENERAL PARTNER'S REQUIRED CAPITAL CONTRIBUTION. The managing general partner's aggregate capital contributions to each partnership must not be less than 25% of all capital contributions to that partnership. This includes such items as the managing general partner's: o credit for the cost of the leases contributed to the partnership, or the fair market value of the leases if the managing general partner has a reason to believe that cost is materially more than fair market value; o credit for organization and offering costs, including the costs of services contributed as organization costs; and o share of partnership equipment costs paid by it to itself as operator under the drilling and operating agreement, which includes its administrative overhead reimbursement and profit on those costs. The managing general partner's capital contributions must be paid or made at the time the costs are required to be paid by the partnership, but not later than the end of the year immediately following the year in which the partnership had its final closing. REVENUES Each partnership's production revenues from all of its wells will be commingled. Thus, regardless of when you subscribe to a partnership you will share in the production revenues from all of the wells in that partnership on the same basis as the other investors in the partnership in proportion to your number of units. 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 as provided in 4, below. 2. INTEREST PROCEEDS. Interest income earned on your subscription proceeds before your partnership's final closing will be credited to your account and paid not later than the partnership's first cash distributions from operations. After your partnership's final closing and until the subscription proceeds are invested in your partnership's operations, any interest income from temporary investments will be allocated pro rata to you and the other investors providing the subscription proceeds. All other interest income, including interest earned on the deposit of production revenues, will be credited as provided in 4, below. 3. EQUIPMENT PROCEEDS. Proceeds from the sale or other disposition of equipment will be credited to the parties charged with the costs of the equipment in the ratio in which the costs were charged. 73 4. PRODUCTION REVENUES. Subject to the managing general partner's subordination obligation as described below, the managing general partner and the investors in a partnership will share in all of that partnership's other revenues, including production revenues, in the same percentage as their respective capital contribution bears to the total partnership capital contributions, except that the managing general partner will receive an additional 7% of that partnership's revenues. However, the managing general partner's total revenue share may not exceed 35% of that partnership's revenues regardless of the amount of its capital contributions. For example, if the managing general partner contributes the minimum of 25% of the total partnership capital contributions and the investors contribute 75% of the total partnership capital contributions, then the managing general partner will receive 32% of the partnership revenues and the investors will receive 68% of the partnership revenues. On the other hand, if the managing general partner contributes 30% of the total partnership capital contributions and the investors contribute 70% of the total partnership capital contributions, then the managing general partner will receive 35% of the partnership revenues, not 37%, because its revenue share cannot exceed 35% of partnership revenues, and the investors will receive 65% of partnership revenues. SUBORDINATION OF PORTION OF MANAGING GENERAL PARTNER'S NET REVENUE SHARE Each partnership is structured to provide you and the other investors with cash distributions equal to a minimum of 10% per unit, based on $10,000 per unit regardless of the actual subscription price for your units, in each of the first five 12-month periods beginning with that partnership's first cash distributions from operations. To help achieve this investment feature, the managing general partner will subordinate up to 50% of its share of the managing general partner's share of partnership net production revenues during this subordination period. o Partnership net production revenues means gross revenues after deduction of the related operating costs, direct costs, administrative costs, and all other costs not specifically allocated. Each partnership's 60-month subordination period will begin with that partnership's first cash distribution from operations to you and the other investors. However, no subordination distributions to you and the other investors will be required until that partnership's first cash distribution after substantially all of the partnership wells have been drilled, completed, and begun producing into a sales line. Subordination distributions will be determined by debiting or crediting current period partnership revenues to the managing general partner as may be necessary to provide the distributions to you and the other investors. At any time during the subordination period the managing general partner is entitled to an additional share of partnership revenues to recoup previous subordination distributions to the extent your cash distributions from that partnership exceed the 10% return of capital described above. The specific formula is set forth in Section 5.01(b)(4)(a) of the partnership agreement. The managing general partner anticipates that you will benefit from the subordination if the price of natural gas and oil received by the partnership and/or the results of the partnership's drilling activities are unable to provide the required return. However, if the wells produce small natural gas and oil volumes or natural gas and oil prices decrease, then even with subordination your cash flow may be very small and you may not receive the 10% return of capital for each of the first five years beginning with the partnership's first cash distribution from operations. As of January 15, 2004, the managing general partner was subordinating a portion or all of its net revenues in two of its previous twelve limited partnerships that currently have the subordination feature in effect. Since 1993 the managing general partner has had a subordination feature in 27 of its partnerships and from time to time it has subordinated its partnership net revenues in 16 of these partnerships. The managing general partner is entitled to recoup these subordination distributions during the subordination period to the extent cash distributions to the investors in these previous partnerships would exceed the specified return to the investors. 74 EXAMPLE OF NET REVENUE SHARING DURING A SUBORDINATION PERIOD.
NET REVENUES TO MANAGING MAXIMUM AMOUNT OF GENERAL PARTNER AND MANAGING GENERAL INVESTORS IF MAXIMUM AMOUNT PERCENTAGE OF PERCENTAGE OF PARTNER'S SHARE OF OF MANAGING GENERAL PARTNERSHIP PARTNERSHIP NET PARTNERSHIP NET PARTNER'S SHARE OF CAPITAL REVENUES WITHOUT REVENUES AVAILABLE FOR PARTNERSHIP NET REVENUES IS ENTITY CONTRIBUTIONS (1) SUBORDINATION (1) SUBORDINATION (2) SUBORDINATED (1)(2) - ------ ----------------- ----------------- ----------------- ------------------- Managing General Partner................25% 32% 16% 16% Investors...............................75% 68% 84%
- ------------------ (1) These percentages are for illustration purposes only and assume the managing general partner's minimum required capital contribution of 25% to each partnership and capital contributions of 75% from you and the other investors. The actual percentages are likely to be different because they will be based on the actual capital contributions of the managing general partner and you and the other investors. However, the managing general partner's total revenue share may not exceed 35% of partnership revenues regardless of the amount of its capital contribution. (2) Each partnership is structured to provide you and the other investors with cash distributions equal to a minimum of 10% per unit, based on $10,000 per unit regardless of the actual subscription price for your units, in each of the first five 12-month periods beginning with the partnership's first cash distributions from operations. To help achieve this investment feature, the managing general partner will subordinate up to 50% of its share of partnership net production revenues during this subordination period. EXAMPLE OF NET REVENUE SHARING AFTER THE END OF A SUBORDINATION PERIOD.
NET REVENUES TO MANAGING MAXIMUM AMOUNT OF GENERAL PARTNER AND MANAGING GENERAL INVESTORS IF MAXIMUM AMOUNT PERCENTAGE OF PERCENTAGE OF PARTNER'S SHARE OF OF MANAGING GENERAL PARTNERSHIP PARTNERSHIP NET PARTNERSHIP NET PARTNER'S SHARE OF CAPITAL REVENUES WITHOUT REVENUES AVAILABLE FOR PARTNERSHIP NET REVENUES IS ENTITY CONTRIBUTIONS (1) SUBORDINATION (1) SUBORDINATION SUBORDINATED (1) - ------ ----------------- ----------------- ------------- ---------------- Managing General Partner.................25% 32% 0% 32% Investors................................75% 68% 68%
- ---------------- (1) These percentages are for illustration purposes only and assume the managing general partner's minimum required capital contribution of 25% to each partnership and capital contributions of 75% from you and the other investors. The actual percentages are likely to be different because they will be based on the actual capital contributions of the managing general partner and you and the other investors. However, the managing general partner's total revenue share may not exceed 35% of partnership revenues regardless of the amount of its capital contribution. TABLE OF PARTICIPATION IN COSTS AND REVENUES The following table sets forth the partnership costs and revenues charged and credited between the managing general partner and you and the other investors in each partnership after deducting from the partnership's gross revenues, the landowner royalties, and any other lease burdens. 75
MANAGING GENERAL PARTNER INVESTORS -------- --------- PARTNERSHIP COSTS Organization and offering costs.....................................................100% 0% Lease costs.........................................................................100% 0% Intangible drilling costs.............................................................0% 100% Equipment costs (1)..................................................................66% 34% Operating costs, administrative costs, direct costs, and all other costs.............(2) (2) PARTNERSHIP REVENUES Interest income......................................................................(3) (3) Equipment proceeds (1)...............................................................66% 34% All other revenues including production revenues..................................(4)(5) (4)(5) PARTICIPATION IN DEDUCTIONS Intangible drilling costs.............................................................0% 100% Depreciation (1).....................................................................66% 34% Percentage depletion allowance.................................................(4)(5)(6) (4)(5)(6)
- -------------- (1) These percentages may vary. If the total equipment costs for all of a partnership's wells that would be charged to you and the other investors exceeds an amount equal to 10% of the subscription proceeds of you and the other investors in that partnership, then the excess will be charged to the managing general partner. Equipment proceeds, if any, will be credited in the same percentage in which the equipment costs were charged. (2) These costs, which also include plugging and abandonment costs of the wells after the wells have been drilled and produced, will be charged to the parties in the same ratio as the related production revenues are being credited. (3) Interest earned on your subscription proceeds before a partnership's final closing will be credited to your account and paid not later than the partnership's first cash distributions from operations. After the partnership's final closing and until proceeds from the offering are invested in the partnership's operations any interest income from temporary investments will be allocated pro rata to the investors providing the subscription proceeds. All other interest income in the partnership, including interest earned on the deposit of operating revenues, will be credited as production revenues are credited. (4) In each partnership the managing general partner and the investors will share in all of the partnership's other revenues in the same percentage as their respective capital contributions bears to the total partnership capital contributions except that the managing general partner will receive an additional 7% of the partnership revenues. However, the managing general partner's total revenue share in a partnership may not exceed 35% of partnership revenues. (5) If a portion of the managing general partner's partnership net production revenues is subordinated, then the actual allocation of partnership revenues between the managing general partner and the investors will vary from the allocation described in (4) above. (6) The percentage depletion allowances will be in the same percentages as the production revenues. ALLOCATION AND ADJUSTMENT AMONG INVESTORS The investors' share as a group of each partnership's revenues, gains, income, costs, expenses, losses, and other charges and liabilities generally will be charged and credited among you and the other investors in that partnership in accordance with the ratio that your respective number of units bears to the number of units held by all investors as a group in that partnership, based on $10,000 per unit regardless of the actual subscription price for an investor's units. These allocations will take into account any investor general partner's status as a defaulting investor general partner. Certain investors, however, will pay a reduced amount for their units as described in "Plan of Distribution." Thus, intangible drilling costs and the investors' share of the equipment costs of drilling and completing the partnership's wells will be charged among you and the other investors in a partnership in accordance with the respective subscription price you and the other investors paid for the units rather than the number of their respective units. 76 DISTRIBUTIONS The managing general partner will review each partnership's accounts at least quarterly to determine whether cash distributions are appropriate and the amount to be distributed, if any, taking into account its subordination obligation discussed above in "-Subordination of Portion of Managing General Partner's Net Revenue Share." Your partnership will distribute funds to you and the other investors that the managing general partner, in its sole discretion, does not believe are necessary for the partnership to retain. Distributions may be reduced or deferred to the extent partnership revenues are used for any of the following: o repayment of borrowings; o cost overruns; o remedial work to improve a well's producing capability; o direct costs and general and administrative expenses of the partnership; o reserves, including a reserve for the estimated costs of eventually plugging and abandoning the wells; or o indemnification of the managing general partner and its affiliates by the partnership for losses or liabilities incurred in connection with the partnership's activities. Also, funds will not be advanced or borrowed for distributions if the distribution amount 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 a partnership to the managing general partner will be made only in conjunction with distributions to you and the other investors in that partnership and only out of funds properly allocated to the managing general partner's account. LIQUIDATION Each partnership will continue for 50 years unless it is terminated earlier by a final terminating event as described below, or an event which causes the dissolution of a limited partnership under the Delaware Revised Uniform Limited Partnership Act. However, if a partnership terminates on 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. Thus, only on a final terminating event will a partnership be liquidated. A final terminating event is any of the following: o the election to terminate the partnership by the managing general partner or the affirmative vote of investors whose units equal a majority of the total units; o the termination of the partnership under Section 708(b)(1)(A) of the Internal Revenue Code because no part of its business is being carried on; or o the partnership ceases to be a going concern. On the partnership's liquidation you will receive your interest in the partnership to which you subscribed. Generally, your interest in the partnership means an undivided interest in the partnership's assets, after payments to the partnership's creditors, in the ratio your capital account bears to all of the capital accounts until they have been reduced to zero. Thereafter, your interest in the remaining partnership assets will equal your interest in the related partnership revenues. Any in-kind property distributions to you from a partnership must be made to a liquidating trust or similar entity, unless you affirmatively consent to receive an in-kind property distribution after being told 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's 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, or to itself or its affiliates at fair market value as determined by an independent expert selected by the managing general partner. Also, if a partnership is liquidated, the managing general partner will be repaid for any debts owed to it by the partnership before there are any payments to you and the other investors in that partnership. 77 CONFLICTS OF INTEREST IN GENERAL Conflicts of interest are inherent in natural gas and oil partnerships involving non-industry investors because the transactions are entered into without arms' length negotiation. Your interests and those of the managing general partner and its affiliates may be inconsistent in some respects or in certain instances, and the managing general partner's actions may not be the most advantageous to you. The following discussion describes certain possible conflicts of interest that may arise for the managing general partner and its affiliates in the course of each partnership. For some of the conflicts of interest, but not all, there are certain limitations on the managing general partner that are designed to reduce, but which will not eliminate, the conflicts. Other than these limitations the managing general partner has no procedures to resolve a conflict of interest and under the terms of the partnership agreement the managing general partner may resolve the conflict of interest in its sole discretion and best interest. The following discussion is materially complete; however, other transactions or dealings may arise in the future that could result in conflicts of interest for the managing general partner and its affiliates. 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 each partnership are reasonable, the compensation has been determined solely by the managing general partner and did not result from negotiations with any unaffiliated third-party dealing at arms' length. The managing general partner and its affiliates will receive compensation and reimbursement from each partnership for their services in drilling, completing, and operating that partnership's wells under the drilling and operating agreement and will receive the other fees described in "Compensation" regardless of the success of that partnership's wells. The managing general partner and its affiliates providing the services or equipment can be expected to profit from the transactions, and it is usually in the managing general partner's best interest to enter into contracts with itself and its affiliates rather than unaffiliated third-parties even if the contract terms, skill, and experience, offered by the unaffiliated third-parties is comparable. The partnership agreement provides that when the managing general partner and any affiliate provide services or equipment to a partnership their fees must be competitive with the fees charged by unaffiliated third-parties in the same geographic area engaged in similar businesses. Also, before the managing general partner and any affiliate may receive competitive fees for providing services or equipment to a partnership they must be engaged, independently of the partnership and as an ordinary and ongoing business, in rendering the services or selling or leasing the equipment and supplies to a substantial extent to other persons in the natural gas and oil industry in addition to the partnerships in which the managing general partner or an affiliate has an interest. 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 that could be obtained in the area. Any services not otherwise described in this prospectus or the partnership agreement for which the managing general partner or an affiliate is to be compensated by a partnership must be: o set forth in a written contract that describes the services to be rendered and the compensation to be paid; and o cancelable without penalty on 60 days written notice by investors whose units equal a majority of the total units. The compensation, if any, will be reported to you in your partnership's annual and semiannual reports, and a copy of the contract will be provided to you on request. 78 There is also a conflict of interest concerning the purchase price if the managing general partner or an affiliate purchases a property from a partnership, which they may do in certain limited circumstances as described in "- Conflicts Involving the Acquisition of Leases - (6) Limitations on Sale of Undeveloped and Developed Leases to the Managing General Partner," below. CONFLICT REGARDING THE DRILLING AND OPERATING AGREEMENT The managing general partner anticipates that all of the wells drilled by each partnership will be drilled and operated under the drilling and operating agreement. This creates a continuing conflict of interest because the managing general partner must monitor and enforce, on behalf of each partnership, its own compliance with the drilling and operating agreement. CONFLICTS REGARDING SHARING OF COSTS AND REVENUES The managing general partner will receive a percentage of revenues greater than the percentage of costs that it pays. This sharing arrangement may create a conflict of interest between the managing general partner and you and the other investors in a partnership concerning the determination of which wells will be drilled by the partnership based on the risk and profit potential associated with the wells. In addition, the allocation of all of the intangible drilling costs to you and the other investors and the majority of the equipment costs to the managing general partner creates a conflict of interest between the managing general partner and you and the other investors concerning whether to complete a well. For example, the completion of a marginally productive well might prove beneficial to you and the other investors, but not to the managing general partner. When a completion decision is made you and the other investors will have already paid the majority of your costs so you will want to pay your share of the additional costs to complete the well if there is a reasonable opportunity to recoup your share of the completion costs plus any portion of the costs paid by you before the completion attempt. You will want to plug the well, however, if it appears likely that you will not recoup all of your share of the additional costs to complete the well. On the other hand, the managing general partner will have paid only a portion of its costs before this time, and it will want to pay its additional equipment costs to complete the well only if it is reasonably certain of recouping its share of the completion costs and making a profit. However, based on its past experience the managing general partner anticipates that most of the wells in the primary areas will have to be completed before it can determine the well's productivity, which would eliminate this potential conflict of interest. In any event, the managing general partner will not cause any well to be plugged and abandoned without a completion attempt unless it makes the decision in accordance with generally accepted oil and gas field practices in the geographic area of the well location. CONFLICTS REGARDING TAX MATTERS PARTNER The managing general partner will serve as each partnership's tax matters partner and represent the partnership before the IRS. The managing general partner will have broad authority to act on behalf of you and the other investors in the partnership in any administrative or judicial proceeding involving the IRS, and this authority may involve conflicts of interest. For example, potential conflicts include: o whether or not to expend partnership funds to contest a proposed adjustment by the IRS, if any, to: o the amount of a partnership's deduction for intangible drilling costs, which is allocated 100% to you and the other investors in the partnership; or o the amount of the managing general partner's depreciation deductions, or the credit to its capital account for contributing the leases to a partnership if the proposed adjustment would decrease the managing general partner's liquidation interest in the partnership; or o the amount of the managing general partner's reimbursement from a partnership for expenses incurred by it in its role as the tax matters partner as a reasonable, ordinary and necessary business deduction. 79 CONFLICTS REGARDING OTHER ACTIVITIES OF THE MANAGING GENERAL PARTNER, THE OPERATOR AND THEIR AFFILIATES The managing general partner will be required to devote to each partnership the time and attention that it considers necessary for the proper management of the partnership's activities. However, the managing general partner has sponsored and continues to manage other natural gas and oil drilling partnerships, which may be concurrent, and will engage in unrelated business activities, either for its own account or on behalf of other partnerships, joint ventures, corporations, or other entities in which it has an interest. This creates a continuing conflict of interest in allocating management time, services, and other activities among the partnerships in this program and its other activities. The managing general partner will determine the allocation of its management time, services, and other functions on an as-needed basis consistent with its fiduciary duties among the partnerships in this program and its 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 a 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: o cannot be pursued by the partnership because of insufficient funds; or o 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 each partnership. Conflicts of interest may arise concerning which wells will be drilled by each partnership in this program and which wells will be drilled by the managing general partner's and its affiliates' other affiliated 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 a partnership in this program bear the costs and risks of drilling a particular well rather than another affiliate. These potential conflicts of interest will be increased if the managing general partner organizes and allocates wells to more than one partnership at a time. To lessen this conflict of interest the managing general partner generally takes a similar interest in other partnerships when it serves as managing general partner and/or driller/operator. The managing general partner anticipates that generally only one partnership will be actively engaged in drilling at any time. However, when the managing general partner must provide prospects to two or more partnerships at the same time it will attempt to treat each partnership fairly on a basis consistent with: o the funds available to the partnerships; and o the time limitations on the investment of funds for the partnerships. Generally, the managing general partner follows a policy of developing prospects in the order of what it believes is the "best available prospect." However, the managing general partner will constantly change its assessment of available prospects based on the acquisition of new leases and information derived from wells already drilled. If more than one partnership in this program has funds available for drilling at the same time, the partnerships will alternate drilling of wells based on the "best available prospect" format. The determination of the "best available prospect" is based on the managing general partner's assessment of the economic potential of a prospect and its suitability to a particular partnership, including the following factors: o estimated reserves; o the targeted geological formations; o natural gas and oil markets; 80 o geological and natural gas and oil market diversification within the partnerships; o the prospect's net revenue interest; o estimated drilling costs; and o limitations imposed by the prospectus and/or the partnership agreement. The partnership agreement gives the managing general partner the authority to cause each partnership in this program to acquire undivided interests in natural gas and oil properties, and to participate with other parties, including other drilling programs previously or subsequently conducted by the managing general partner or its affiliates, in the conduct of its drilling operations on those properties. If conflicts between the interest of a partnership in this program and other drilling partnerships do arise, then the managing general partner may be unable to resolve those conflicts to the maximum advantage of the partnership in this program because the managing general partner must deal fairly with the investors in all of its drilling partnerships. In addition, subject to the restrictions set forth below, the managing general partner decides which prospects and what interest in the prospects to transfer to a partnership. This will result in a subsequent partnership sponsored by the managing general partner benefiting from knowledge gained through a prior partnership's drilling experience in an area and acquiring a prospect adjacent to the prior partnership's prospect. No procedures, other than the guidelines set forth below and in " - Procedures to Reduce Conflicts of Interest," have been established by the managing general partner to resolve any conflicts that may arise. The partnership agreement provides that the managing general partner and its affiliates will abide by the guidelines set forth below. However, with respect to (2), (3), (4), (5), (7) and (9) there is an exception in the partnership agreement for another program in which the interest of the managing general partner is substantially similar to or less than its interest in the partnerships. (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. o A determination of fair market value must be supported by an appraisal from an independent expert and maintained in the partnership's records for at least six years. (2) EQUAL PROPORTIONATE INTEREST. When the managing general partner sells or transfers an oil and gas interest to a partnership, it must, at the same time, sell or transfer to the partnership an equal proportionate interest in all of its other property in the same prospect. o The term "prospect" generally means an area which is believed to contain commercially productive quantities of natural gas or oil. However, a prospect will be limited to the drilling or spacing unit on which one well will be drilled if the following two conditions are met: o the well is being drilled to a geological feature which contains proved reserves as defined below; and o the drilling or spacing unit protects against drainage. 81 The managing general partner believes that for a prospect located in Ohio, Pennsylvania and New York on which a well will be drilled to test the Clinton/Medina geologic formation or the Mississippian and/or Upper Devonian Sandstone reservoirs, a prospect will consist of the drilling and spacing unit because it will meet the test in the preceding sentence. o Proved reserves, generally, are the estimated quantities of natural gas and oil which have been demonstrated to be recoverable in future years with reasonable certainty under existing economic and operating conditions. Proved reserves include proved undeveloped reserves which generally are reserves expected to be recovered from existing wells where a relatively major expenditure is required for recompletion or from new wells on undrilled acreage. Reserves on undrilled acreage will be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved Reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. The managing general partner anticipates that the majority of the wells drilled by each partnership will develop the Clinton/Medina geologic formation or the Mississippian and/or 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 throughout the primary areas where each partnership's wells will be situated. To lessen this conflict of interest, for five years the managing general partner may not drill any well: o 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 o in the Mississippian/Upper Devonian Sandstone reservoirs in Fayette and Green Counties, Pennsylvania within at least 1,000 feet from a producing well, although a partnership may drill a new well or re-enter an existing well which is closer than 1,000 feet to a plugged and abandoned well. If a partnership abandons its interest in a well, then this restriction will continue for one year following the abandonment. There are no similar prohibitions for the other primary areas. (3) SUBSEQUENTLY ENLARGING PROSPECT. In areas where the prospect is not limited to the drilling or spacing unit and the area constituting a partnership's prospect is subsequently enlarged based on geological information, which is later acquired, then there is the following special provision: o 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 a partnership less than all of its ownership in any prospect, then it must comply with the following conditions: o the retained interest must be a proportionate working interest; o 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 o the managing general partner's revenue interest must not exceed the amount proportionate to its retained working interest. 82 For example, if the managing general partner transfers 50% of its working interest in a prospect to a partnership and retains a 50% working interest, then the partnership will not pay any of the costs associated with the managing general partner's retained working interest as a part of the transfer. This limitation does not prevent the managing general partner and its affiliates from subsequently dealing with their retained working interest as they may choose with unaffiliated parties or affiliated partnerships. For example, the managing general partner may sell its retained working interest to a third-party for a profit. (5) LIMITATIONS ON ACTIVITIES OF THE MANAGING GENERAL PARTNER AND ITS AFFILIATES ON LEASES ACQUIRED BY A PARTNERSHIP. For a five year period after the final closing of a partnership, if the managing general partner proposes to acquire an interest from an unaffiliated person in a prospect in which the partnership owns an interest or in a prospect in which the partnership's interest has been terminated without compensation within one year before the proposed acquisition, then the following conditions apply: o 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 o if the managing general partner currently owns a proportionate interest in the prospect separately from the partnership, then the interest to be acquired must be divided in the same proportion between the managing general partner and the partnership as the other property in the prospect. However, if the partnership does not have the cash or financing to buy the additional interest, then the managing general partner is also prohibited from buying the additional interest. (6) LIMITATIONS ON SALE OF UNDEVELOPED AND DEVELOPED LEASES TO THE MANAGING GENERAL PARTNER. The managing general partner and its affiliates, other than an affiliated partnership as set forth in (7) below, may not purchase undeveloped leases or receive a farmout from a partnership other than at the higher of cost or fair market value. Farmouts to the managing general partner and its affiliates also must be made as set forth in (9) below. The managing general partner and its affiliates, other than an affiliated income program, may not purchase any producing natural gas or oil property from a partnership unless: o the sale is in connection with the liquidation of the partnership; or o the managing general partner's well supervision fees under the drilling and operating agreement for the well have exceeded the net revenues of the well, determined without regard to the managing general partner's well supervision fees for the well, for a period of at least three consecutive months. In both cases, the sale must be at fair market value supported by an appraisal of an independent expert selected by the managing general partner. The appraisal of the property must be maintained in the partnership's records for at least six years. (7) TRANSFER OF LEASES BETWEEN AFFILIATED LIMITED PARTNERSHIPS. The transfer of an undeveloped lease from a partnership to an affiliated drilling limited partnership must be made at fair market value if the undeveloped lease has been held for more than two years. Otherwise, the transfer may be made at cost if the managing general partner deems it to be in the best interest of the partnership. An affiliated income program may purchase a producing natural gas and oil property from a partnership at any time at: o fair market value as supported by an appraisal from an independent expert if the property has been held by the partnership for more than six months or there have been significant expenditures made in connection with the property; or 83 o cost as adjusted for intervening operations if the managing general partner deems it to be in the best interest of the partnership. However, these prohibitions do not apply to joint ventures or farmouts among affiliated partnerships, provided that: o the respective obligations and revenue sharing of all parties to the transaction are substantially the same; and o 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. Each partnership must acquire only leases that are reasonably expected to meet the stated purposes of the partnership. Also, no leases may be acquired for the purpose of a subsequent sale, farmout or other disposition unless the acquisition is made after a well has been drilled to a depth sufficient to indicate that the acquisition would be in the partnership's best interest. (9) FARMOUT. The managing general partner will not assign to a partnership the working interest in a prospect for the purpose of a subsequent farmout, sale or other disposition. The managing general partner will not enter into a farmout to avoid paying its share of the costs related to drilling an undeveloped lease. However, the managing general partner's decision with respect to making a farmout and the terms of a farmout from a partnership involve conflicts of interest since the managing general partner may benefit from cost savings and reduction of risk. The partnership may farmout an undeveloped lease or well activity to the managing general partner, its affiliates or an unaffiliated third-party only if the managing general partner, exercising the standard of a prudent operator, determines that: o the partnership lacks the funds to complete the oil and gas operations on the lease or well and cannot obtain suitable financing; o drilling on the lease or the intended well activity would concentrate excessive funds in one location, creating undue risks to the partnership; o the leases or well activity have been downgraded by events occurring after assignment to the partnership so that development of the leases or well activity would not be desirable; or o the best interests of the partnership would be served. If the partnership farmouts a lease or well activity, the managing general partner must retain on behalf of the partnership the economic interests and concessions as a reasonably prudent oil and gas operator would or could retain under the circumstances prevailing at the time, consistent with industry practices. However, if the farmout is made to the managing general partner or its affiliates there is a conflict of interest since the managing general partner will represent both the partnership and itself or an affiliate. Although the conflict of interest may be resolved to the managing general partner's benefit, the managing general partner must still retain on behalf of the partnership the economic interests and concessions as a reasonably prudent oil and gas operator would or could retain under the circumstances prevailing at the time, consistent with industry practices. CONFLICTS BETWEEN INVESTORS AND THE MANAGING GENERAL PARTNER AS AN INVESTOR The managing general partner, its officers, directors, and affiliates may subscribe for units in each partnership and the price of their units will be reduced by 10.5% as described in "Plan of Distribution." Even though they pay a reduced price for their units these investors generally will: 84 o share in the partnership's costs, revenues, and distributions on the same basis as the other investors as described in "Participation in Costs and Revenues"; and o have the same voting rights, except as discussed below. 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 as described in "Summary of Partnership Agreement - Voting Rights." LACK OF INDEPENDENT UNDERWRITER AND DUE DILIGENCE INVESTIGATION The terms of this offering, the partnership agreement, and the drilling and operating agreement were determined by the managing general partner without arms' length negotiations. You and the other investors have not been separately represented by legal counsel, who might have negotiated more favorable terms for you and the other investors in this offering and the agreements. Also, there was not an extensive in-depth "due diligence" investigation of the existing and proposed business activities of the partnerships and the managing general partner that would be provided by independent underwriters. Although Anthem Securities, which is affiliated with the managing general partner, serves as dealer-manager 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 The managing general partner anticipates that its legal counsel will also serve as legal counsel to each 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 in a partnership, then the managing general partner will cause you and the other investors to retain separate counsel. Also, if counsel advises the managing general partner that counsel reasonably believes its representation of a partnership will be adversely affected by its responsibilities to the managing general partner, then the managing general partner will cause you and the other investors in a partnership to retain separate counsel. CONFLICTS REGARDING PRESENTMENT FEATURE You and the other investors in a partnership have the right to present your units in the partnership to the managing general partner for purchase beginning with the fifth calendar year after the end of the calendar year in which your partnership closes. This creates the following conflicts of interest between you and the managing general partner. o The managing general partner may suspend the presentment feature if it does not have the necessary cash flow or it cannot borrow funds for this purpose on terms which it deems reasonable. Both of these determinations are subjective and will be made in the managing general partner's sole discretion. o The managing general partner will also determine the purchase price based on a reserve report that it prepares and is reviewed by an independent expert that it chooses. The formula for arriving at the purchase price has many subjective determinations that are within the discretion of the managing general partner. CONFLICTS REGARDING MANAGING GENERAL PARTNER WITHDRAWING AN INTEREST A conflict of interest is created with you and the other investors by the managing general partner's right to mortgage its interest or withdraw an interest in each partnership's wells equal to or less than its revenue interest to be used as collateral for a loan to the managing general partner. If there was a default under the loan, this could reduce or eliminate the amount of the managing general partner's partnership net production revenues available for its subordination obligation to you and the other investors. Also under certain circumstances, if the managing general partner made a subordination distribution to you and the other investors after a default, then the lender may be able to recoup from you and the other investors that subordination distribution. CONFLICTS REGARDING ORDER OF PIPELINE CONSTRUCTION AND GATHERING FEES The managing general partner may choose well locations along the Atlas Pipeline Partners gathering system which would benefit its parent company by providing more gathering fees to Atlas Pipeline Partners, even if there are other well locations available in the area or other areas which offer the partnerships a greater potential return. However, the managing general partner believes this conflict of interest is substantially reduced because the managing general partner expects to make the largest single capital contribution in each partnership as explained in "Capitalization and Source of Funds and Use of Proceeds." Thus, it is in the best interest of its parent company for the managing general partner to choose prospects for a partnership to drill which have the greatest potential reserves even if they are not connected to the Atlas Pipeline Partners gathering system. In addition, Atlas America or an affiliate will operate the Atlas Pipeline Partners gathering system. Thus, the expansion of the Atlas Pipeline Partners gathering system will be within the control of the managing general partner's affiliate, which will attempt to expand the Atlas Pipeline Partners gathering system to those areas with the greatest number of wells with the greatest potential reserves. 85 The managing general partner's affiliates are obligated through their agreement with Atlas Pipeline Partners to pay the difference between the amount each partnership pays for gathering fees to the managing general partner as set forth in "Compensation - Gathering Fees," and the greater of $.35 per mcf or 16% of the gross sales price for the natural gas. This provides an incentive to the managing general partner to increase the amount of the gathering fees paid by each partnership to it, which are not fixed and may change as described in "Compensation-Gathering Fees." However, the gathering fees paid to the managing general partner may not exceed competitive rates. 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 each partnership will reduce the conflicts of interest. (1) FAIR AND REASONABLE. The managing general partner may not sell, transfer, or convey any property to, or purchase any property from, a partnership except pursuant to transactions that are fair and reasonable; nor take any action with respect to the assets or property of a partnership which does not primarily benefit the partnership. (2) NO COMPENSATING BALANCES. The managing general partner may not use a partnership's funds as a compensating balance for its own benefit. Thus, a partnership's funds may not be used to satisfy any deposit requirements imposed by a bank or other financial institution on the managing general partner for its own corporate purposes. (3) FUTURE PRODUCTION. The managing general partner may not commit the future production of a partnership well exclusively for its own benefit. (4) DISCLOSURE. Any agreement or arrangement that binds a partnership must be fully disclosed in this prospectus. (5) NO LOANS FROM A PARTNERSHIP. A partnership may not loan money to the managing general partner. (6) NO REBATES. The managing general partner may not participate in any business arrangements which would circumvent these guidelines including receiving rebates or give-ups. (7) SALE OF ASSETS. The sale of all or substantially all of the assets of a partnership may only be made with the consent of investors whose units equal a majority of the total units. (8) PARTICIPATION IN OTHER PARTNERSHIPS. If a 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: 86 o there may be no duplication or increase in organization and offering expenses, the managing general partner's compensation, partnership expenses, or other fees and costs; o there may be no substantive change in the fiduciary and contractual relationship between the managing general partner and you and the other investors; and o there may be no diminishment in your voting rights. (9) INVESTMENTS. A partnership's funds may not be invested in the securities of another person except in the following instances: o investments in working interests made in the ordinary course of the partnership's business; o temporary investments in income producing short-term highly liquid investments, in which there is appropriate safety of principal, such as U.S. Treasury Bills; o multi-tier arrangements meeting the requirements of (8) above; o investments involving less than 5% of the total subscription proceeds of the partnership that are a necessary and incidental part of a property acquisition transaction; and o investments in entities established solely to limit the partnership's liabilities associated with the ownership or operation of property or equipment, provided that duplicative fees and expenses are prohibited. (10) SAFEKEEPING OF FUNDS. The managing general partner may not employ, or permit another to employ, the funds or assets of a partnership in any manner except for the exclusive benefit of the partnership. The managing general partner has a fiduciary responsibility for the safekeeping and use of all funds and assets of each partnership whether or not in its possession or control. (11) ADVANCE PAYMENTS. Advance payments by each partnership to the managing general partner and its affiliates are prohibited except when advance payments are required to secure the tax benefits of prepaid intangible drilling costs and for a business purpose. POLICY REGARDING ROLL-UPS It is possible at some indeterminate time in the future that each partnership may become involved in a roll-up. In general, a roll-up means a transaction involving the acquisition, merger, conversion, or consolidation of a 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: o increasing the compensation of the managing general partner; o amending your voting rights; o listing the units on a national securities exchange or on NASDAQ; o changing the partnership's fundamental investment objectives; or o materially altering the partnership's duration. If a roll-up should occur in the future the partnership agreement provides various policies which include the following: 87 o an independent expert must appraise all partnership assets, and you must receive a summary of the appraisal in connection with a proposed roll-up; o if you vote "no" on the roll-up proposal, then you will be offered a choice of: o accepting the securities of the roll-up entity; or o one of the following: o remaining a partner in the partnership and preserving your units in the partnership on the same terms and conditions as existed previously; or o receiving cash in an amount equal to your pro-rata share of the appraised value of the partnership's net assets; and o the partnership will not participate in a proposed roll-up: o unless approved by investors whose units equal 66% of the total units; o which would result in the diminishment of your voting rights under the roll-up entity's chartering agreement; o which includes provisions which would operate to materially impede or frustrate the accumulation of shares by you of the securities of the roll-up entity; o 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 o in which any of the transaction costs would be borne by the partnership if the proposed roll-up is not approved by investors whose units equal 66% of the total units. FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER IN GENERAL The managing general partner will manage your partnership and its assets. In conducting your partnership's affairs the managing general partner is accountable to you as a fiduciary, which under Delaware law generally means that the managing general partner must exercise due care and deal fairly with you and the other investors. Neither the partnership agreement nor any other agreement between the managing general partner and each 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, 4.03, 4.04, 4.05, and 4.06 of the partnership agreement. In this regard, the partnership agreement does permit the managing general partner and its affiliates to: o have business interests or activities that may conflict with the partnerships if they determine that the business opportunity either: o cannot be pursued by the partnership because of insufficient funds; or o it is not appropriate for the partnership under the existing circumstances; o devote only so much of their time as is necessary to manage the affairs of each partnership; 88 o conduct business with the partnerships in a capacity other than as managing general partner or sponsor as described in ss.ss.4.01, 4.02, 4.03, 4.04, 4.05 and 4.06 of the partnership agreement; o manage multiple programs simultaneously; and o be indemnified and held harmless as described below in "- Limitations on Managing General Partner Liability as Fiduciary." Other than as set forth above, the partnership agreement does not excuse the managing general partner from liability or provide it with any defense for breach of its fiduciary duty. The fiduciary duty owed by the managing general partner to the partnership is analogous to the fiduciary duty owed by directors to a corporation and its stockholders and is subject to the same rule, commonly referred to as the "business judgment rule," that directors are not liable for mistakes made in the good faith exercise of honest business judgment or for losses incurred in the good faith performance of their duties when performed with such care as an ordinarily prudent person would use. As a result of the business judgment rule, the managing general partner may not be held liable for mistakes made or losses incurred in the good faith exercise of reasonable business judgment as described below in " - Limitations on Managing General Partner Liability as Fiduciary." If the managing general partner breaches its fiduciary responsibilities, then you are entitled to an accounting and the recovery of any economic loss caused by the breach. The Delaware Revised Uniform Limited Partnership Act provides that a limited partner may institute legal action (a "derivative" action) on a partnership's behalf to recover damages from a third-party when the managing general partner refuses to institute the action or where an effort to cause the managing general partner to do so is not likely to succeed. In addition, the statutory or case law may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners (a "class action") to recover damages from the managing general partner for violations of its fiduciary duties to the limited partners. Because this is a rapidly expanding and changing area of the law, you are urged to consult your own counsel if you have questions concerning the managing general partner's duties. 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 each partnership and to you and the other investors for any loss suffered by your partnership or you and the other investors in the partnership which arises out of any action or inaction on their part if: o they determined in good faith that the course of conduct was in the best interest of the partnership; o they were acting on behalf of, or performing services for, the partnership; and o their course of conduct did not constitute negligence or misconduct. In addition, the partnership agreement provides for indemnification of the managing general partner, the operator, and their affiliates by each partnership against any losses, judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by them in connection with that partnership provided that they meet the standards set forth above. However, there is a more restrictive standard for indemnification for losses arising from or out of an alleged violation of federal or state securities laws. Also, to the extent that any indemnification provision in the partnership agreement purports to include indemnification for liabilities arising under the Securities Act of 1933, as amended, you should be aware that, in the SEC's opinion, this indemnification is contrary to public policy and therefore unenforceable. Payments arising from the indemnification or agreement to hold harmless are recoverable only out of a partnership's: o tangible net assets; o revenues; and o insurance proceeds. 89 Still, use of partnership funds or assets for indemnification of the managing general partner, the operator, or an affiliate would reduce amounts available for partnership operations or for distribution to you and the other investors. A partnership may not pay the cost of the portion of any insurance that insures the managing general partner, the operator, or an affiliate against any liability for which they cannot be indemnified. However, a partnership's funds can be advanced to them for legal expenses and other costs incurred in any legal action for which indemnification is being sought if the partnership has adequate funds available and certain conditions in the partnership agreement are met. The effect of the foregoing provisions and the business judgment rule may be to limit your recourse against the managing general partner. MATERIAL FEDERAL INCOME TAX CONSEQUENCES SUMMARY OF TAX OPINION This section of the prospectus is a summary of the tax opinion and of all the material federal income tax consequences of the purchase, ownership and disposition of the investor general partner units and the limited partner units. The managing general partner has received and will rely on the tax opinion of special counsel, Kunzman & Bollinger, Inc., Oklahoma City, Oklahoma, which is included as Exhibit 8 to the Registration Statement, with respect to the material federal income tax issues of an investment in a partnership. Accordingly, no advance ruling on any tax consequence of an investment in a partnership will be requested from the IRS. However, 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 guaranteed. The IRS may challenge the deductions claimed by a partnership or you, or the taxable year in which the deductions are claimed, and no guaranty can be given that the challenge would not be upheld if litigated. Special counsel's opinions are based in part on certain factual representations of the managing general partner, which special counsel has assumed to be correct for purposes of the tax opinion, and other factual assumptions of special counsel which are set forth in the tax opinion. In this regard, the managing general partner has represented that "typical investors" in each partnership will be natural persons who purchase units in this offering and are U.S. citizens. You are strongly urged to read the entire tax opinion. See "Additional Information" for instructions in how to obtain a copy of the tax opinion. In special counsel's opinion the following tax treatment with respect to a typical investor is the proper federal income tax treatment and will be upheld if challenged by the IRS and litigated. o PARTNERSHIP CLASSIFICATION. Each Partnership will be classified as a partnership for federal income tax purposes, and not as a corporation. The Partnerships, as such, will not pay any federal income taxes, and all items of income, gain, loss and deduction of the Partnerships will be reportable by the Partners in the Partnership in which they invest. o PASSIVE ACTIVITY CLASSIFICATION. o Generally, the passive activity limitations on losses under ss.469 of the Code will apply to the Limited Partners in a Partnership, but will not apply to the Investor General Partners in the Partnership before the conversion of the Investor General Partner Units to Limited Partner Units in the Partnership. o A Partnership's income and gain from its natural gas and oil properties which are allocated to its Limited Partners, other than net income allocated to converted Investor General Partners, generally will be characterized as passive activity income which may be offset by passive activity losses. 90 o Income or gain attributable to investments of working capital of a Partnership will be characterized as portfolio income, which cannot be offset by passive activity losses. o NOT A PUBLICLY TRADED PARTNERSHIP. None of the Partnerships will be treated as a publicly traded partnership under the Code. o 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, Tangible Costs, organization and syndication fees and other items which are required to be capitalized, are currently deductible. o INTANGIBLE DRILLING COSTS. Although each Partnership will elect to deduct currently all Intangible Drilling Costs, each Participant may still elect to capitalize and deduct all or part of his share of his Partnership's Intangible Drilling Costs ratably over a 60 month period as discussed in "- Alternative Minimum Tax," below. Subject to the foregoing, Intangible Drilling Costs paid by a Partnership under the terms of bona fide drilling contracts for the Partnership's wells will be deductible in the taxable year in which the payments are made and the drilling services are rendered, assuming the amounts are reasonable consideration based on the Managing General Partner's representations, and subject to certain restrictions summarized below, including basis and "at risk" limitations, and the passive activity loss limitation with respect to the Limited Partners. o PREPAYMENTS OF INTANGIBLE DRILLING COSTS. Depending primarily on when each Partnership's subscriptions are received, the Managing General Partner anticipates that Atlas America Public #14-2004 L.P. will prepay in 2004 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2005. In addition, the Managing General Partner anticipates that Atlas America Public #14-2005(B) L.P., which may close on December 31, 2005, may prepay in 2005 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2006. Assuming that the amounts of any prepaid Intangible Drilling Costs of a Partnership are reasonable consideration based on the Managing General Partner's representations, and based in part on the factual assumptions set forth below, the prepayments of Intangible Drilling Costs will be deductible in the year in which they are made even though all Working Interest owners in the well will not be required to prepay Intangible Drilling Costs, 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 under each Partnership's Drilling and Operating Agreement: o the estimated Intangible Drilling Costs are required to be prepaid for specified wells to be drilled and, if warranted, completed; o the drilling of all of the specified wells and substitute wells, if any, is required to be, and actually is, begun before the close of the 90th day after the close of the Partnership's taxable year in which the prepayments are made, and the wells are continuously drilled until completed, if warranted, or abandoned; and o the required prepayments are not refundable to the Partnership and any excess prepayments for Intangible Drilling Costs are applied to Intangible Drilling Costs of the other specified wells or substitute wells. 91 o DEPLETION ALLOWANCE. The greater of cost depletion or percentage depletion will be available to qualified Participants as a current deduction against their share of their Partnership's natural gas and oil production income, subject to certain restrictions summarized below. o MACRS. Each Partnership's reasonable costs for equipment placed in its respective productive wells which cannot be deducted immediately ("Tangible Costs") will be eligible for cost recovery deductions under the Modified Accelerated Cost Recovery System ("MACRS"), generally over a seven year "cost recovery period" beginning in the taxable year each well is completed and made capable of production, i.e. placed in service, subject to certain restrictions summarized below, including basis and "at risk" limitations, and the passive activity loss limitation in the case of the Limited Partners. o TAX BASIS OF UNITS. Each Participant's initial adjusted tax basis in his Units will be the purchase price paid for the Units. o AT RISK LIMITATION ON LOSSES. Each Participant's initial "at risk" amount in the Partnership in which he invests will be the purchase price paid for the Units, assuming that: o any amount borrowed by a Participant and contributed to the Partnership is not borrowed from a Person who has an interest in the Partnership, other than as a creditor, or a "related person", as that term is defined in ss.465 of the Code, to a Person, other than the Participant, having an interest in the Partnership, other than as a creditor, and the Participant is severally, primarily, and personally liable for the borrowed amount; and o the Participant has not protected himself from loss for amounts contributed to the Partnership through nonrecourse financing, guarantees, stop loss agreements or other similar arrangements. o 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 natural gas and oil properties, is substantial in light of a Participant's tax attributes that are unrelated to the Partnership in which he invests, the allocations will have "substantial economic effect" and will govern the Participant's share of those items to the extent the allocations do not cause or increase a deficit balance in his Capital Account. o SUBSCRIPTION. No gain or loss will be recognized by the Participants on payment of their subscriptions to the Partnership in which they invest. o NO TAX SHELTER REGISTRATION. None of the Partnerships is required to register with the IRS as a tax shelter. This opinion is based in part on the Managing General Partner's representations that none of the Partnerships has a tax shelter ratio greater than 2 to 1 and each Partnership will be operated as described in the Prospectus. o PROFIT MOTIVE, IRS ANTI-ABUSE RULE AND POTENTIALLY RELEVANT JUDICIAL DOCTRINES. The Partnerships will possess the requisite profit motive underss.183 of the Code, and the IRS anti-abuse rule in Treas. Reg.ss.1.701-2 and certain potentially relevant judicial doctrines will not have a material adverse effect on the tax consequences of an investment in a Partnership by a typical Participant as described in our opinions. These opinions are based in part on the results of the previous partnerships sponsored by the Managing General Partner as set forth in "Prior Activities" in the Prospectus, and the Managing General Partner's representations. These representations include that each Partnership will be operated as described in the Prospectus (see "Management" and "Proposed Activities" in the Prospectus), and the principal purpose of each Partnership is to locate, produce and market natural gas and oil on a profitable basis, apart from tax benefits. These representations are also supported by the geological evaluations and the other information for the Partnerships' proposed drilling areas and the specific Prospects proposed to be drilled Atlas America Public #14-2004 L.P. which are included in Appendix A to the Prospectus. 92 o OVERALL EVALUATION OF TAX BENEFITS. The tax benefits of each Partnership, in the aggregate, which are a significant feature of an investment in a Partnership by a typical Participant will be realized as contemplated by the Prospectus. This opinion is based on our conclusion that substantially more than half of the material federal income tax benefits of each Partnership, in terms of their financial impact on a typical Participant in the Partnership, will be realized if challenged by the IRS. The discussion in the Prospectus under the caption "MATERIAL FEDERAL INCOME TAX CONSEQUENCES," insofar as it contains statements of federal income tax law, is correct in all material respects. SUMMARY DISCUSSION OF THE MATERIAL FEDERAL INCOME TAX CONSEQUENCES OF AN INVESTMENT IN A PARTNERSHIP IN GENERAL Special counsel's tax opinions are limited to those set forth above. The following is a summary of all of the material federal income tax consequences of the purchase, ownership and disposition of investor general partner units and limited partner units discussed in the tax opinion which will apply to typical investors in each partnership. Different tax considerations than those addressed in this discussion may apply to foreign persons, corporations, partnerships, trusts and other prospective investors which are not treated as typical investors in the partnerships for federal income tax purposes. Also, the proper treatment of the tax attributes of a partnership by a typical investor on his individual federal income tax return may vary from that of another typical investor. This is because the practical utility of the tax attributes of any investment depends largely on each investor's particular income tax position in the year in which items of income, gain, loss, deduction or credit are properly taken into account in computing his federal income tax liability. Accordingly, you are urged to seek qualified, professional assistance in evaluating the potential tax consequences to you of an investment in a partnership with specific reference to your own tax situation. PARTNERSHIP CLASSIFICATION For federal income tax purposes a partnership is not a taxable entity. The partners, rather than the partnership, receive any deductions, 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. Each partnership will be formed as a limited partnership under the Delaware Revised Uniform Limited Partnership Act which describes each partnership as a "partnership." Thus, each partnership automatically will be classified as a partnership unless it elects to be classified as a corporation. In this regard, the managing general partner has represented that none of the partnerships will elect to be taxed as a corporation. LIMITATIONS ON PASSIVE ACTIVITIES Under the passive activity rules of the Internal Revenue Code, all income of a taxpayer who is subject to the rules is categorized as: o income from passive activities such as limited partners' interests in a business; o active income such as salary, bonuses, etc.; or o 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 indefinitely, but not back, and used to offset future years' passive activity income. 93 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 in which they invest and generally will be subject to the passive activity limitations. Investor general partners also do not materially participate in the partnership in which they invest. However, because each partnership will own only "working interests," as defined in the Internal Revenue Code, in its wells and investor general partners will not have limited liability under Delaware law until they are converted to limited partners, their deductions generally will not be treated as passive deductions under the Internal Revenue Code before the conversion. However, if an investor general partner invests in a partnership through an entity which limits his liability, for example, a limited partnership in which he is not a general partner, a limited liability company or an S corporation, then generally he will be subject to the passive activity limitations the same as a limited partner. Contractual limitations on the liability of investor general partners under the partnership agreement, however, such as insurance, limited indemnification by the managing general partner, etc. will not cause investor general partners to be subject to the passive activity loss limitation. 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 passive income from a publicly traded partnership. A publicly traded partnership is a partnership whose interests are traded on an established securities market or that are readily tradable on either a secondary market or the substantial equivalent of a secondary market. However, due primarily to the substantial restrictions under the partnership agreement on your ability to transfer your units in the partnership in which you invest, in the opinion of special counsel none of the partnerships will be treated as a publicly traded partnership under the Internal Revenue Code. (See "Transferability of Units - Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement.") CONVERSION FROM INVESTOR GENERAL PARTNER TO LIMITED PARTNER. If you invest in a partnership as an investor general partner, then your share of the partnership's deduction for intangible drilling costs in the year in which you invest will not be subject to the passive activity loss limitation because your investor general partner units will not be converted to limited partner units until after all of the partnership's wells have been drilled and completed. The managing general partner anticipates that the conversion will be in 2005 for Atlas America Public #14-2004 L.P. and in 2006 for both Atlas America Public #14-2005(A) L.P. and Atlas America Public #14-2005(B) L.P. (See "Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners," and "- Drilling Contracts," below.) After the investor general partner units have been converted to limited partner units, each former investor general partner will have limited liability as a limited partner under the Delaware Revised Uniform Limited Partnership Act with respect to his interest in his partnership's activities after the date of the conversion. Concurrently, the former investor general partner will become subject to the passive activity rules as a limited partner. However, he previously will have received a non-passive loss as an investor general partner in the year in which he invested in a partnership as a result of the partnership's deduction for intangible drilling costs. Therefore, the Internal Revenue Code requires that his net income from the partnership's wells after his conversion to a limited partner must continue to be characterized as non-passive income which cannot be offset with passive losses. The conversion of the investor general partner units into limited partner units should not have any other adverse tax consequences to an investor general partner unless his 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 the 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 AND METHOD OF ACCOUNTING Each partnership intends to adopt a calendar year taxable year and will use the accrual method of accounting for federal income tax purposes. 94 2004 AND 2005 EXPENDITURES The managing general partner anticipates that all of your partnership's subscription proceeds will be expended in the year in which you invest in the partnership, and that your share of the partnership's income and deductions, including the deduction for intangible drilling costs, will be reflected on your federal income tax return for that period. Depending primarily on when each partnership's subscription proceeds are received, the managing general partner anticipates that Atlas America Public #14-2004 L.P. will prepay in 2004 most, if not all, of its intangible drilling costs for drilling activities that will begin in 2005. In addition, the managing general partner anticipates that Atlas America Public #14-2005(B) L.P., which may close on December 31, 2005, may prepay in 2005 most, if not all, of its intangible drilling costs for drilling activities that will begin in 2006. The deductibility of these advance payments in the year in which you invest in the partnership cannot be guaranteed. (See "- Drilling Contracts," below.) The managing general partner does not anticipate that Atlas America Public #14-2005(A) L.P., which has a targeted final closing date of May 31, 2005 (which is not binding on the partnership), will prepay any intangible drilling costs in 2005 for drilling activities that will begin in 2006. 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 that the amounts payable by each partnership to the managing general partner and its affiliates, including the amounts payable to the managing general partner or its affiliates as general drilling contractor, are reasonable amounts which would ordinarily be paid for similar services in similar transactions. The fees paid to the managing general partner and its affiliates by the partnerships will not be currently deductible, however, to the extent they are: o in excess of reasonable compensation; o properly characterized as organization or syndication fees or other capital costs such as the acquisition cost of the leases; or o not "ordinary and necessary" business expenses. In the event of an audit, payments to the managing general partner and its affiliates by a partnership will be scrutinized by the IRS to a greater extent than payments to an unrelated party. INTANGIBLE DRILLING COSTS Subject to the limitations on deductions and losses summarized elsewhere in this discussion, including the basis and "at risk" limitations, and the passive activity loss limitation in the case of limited partners, you will be entitled to deduct your share of your partnership's 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. If a partnership re-enters an existing well as described in "Proposed Activities - Primary Areas of Operations - Mississippian/Upper Devonian Sandstone Reservoirs, Fayette County, Pennsylvania," the costs of deepening the well and completing it to deeper reservoirs, if any, other than equipment costs, generally will be treated as intangible drilling costs. Drilling and completion costs of a re-entry well which are not related to deepening the well, if any, however, other than equipment costs, generally will be treated as operating expenses which should be expensed in the taxable year they are incurred for federal income tax purposes. Those costs (other than equipment costs) of the re-entry well, however, will not be characterized as operating costs, instead of intangible drilling costs, for purposes of allocating the payment of the costs between the managing general partner and the investors under the partnership agreement. Your deduction for intangible drilling costs generally will be treated as ordinary income if a property or your units are sold at a gain. Also, productive-well intangible drilling costs may subject you to an alternative minimum tax in excess of regular tax unless you elect to deduct all or part of these costs ratably over a 60-month period as discussed in "- Alternative Minimum Tax," below. 95 Under the partnership agreement not less than 90% of the subscription proceeds received by your partnership from you and the other investors will be used to pay 100% of the partnership's intangible drilling costs of drilling and completing its wells. The IRS could challenge the characterization of a portion of these costs as currently deductible intangible drilling costs and recharacterize the costs as some other item which may not be currently deductible. However, this would have no effect on the allocation and payment of the intangible drilling costs by you and the other investors under the partnership agreement. You are urged to consult with your own personal tax advisor concerning the tax benefits to you of the deduction for intangible drilling costs in the partnership in which you invest in light of your own tax situation. DRILLING CONTRACTS Each partnership will enter into the drilling and operating agreement with the managing general partner or its affiliates, acting 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 each partnership, assuming a 100% working interest in each well, it will have reimbursement of general and administrative overhead of $12,722 per net well and a profit of 15% (approximately $22,558) per net well with respect to the intangible drilling costs and the portion of equipment costs paid by you and the other investors in your partnership 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 profit per net well also could be more or less than the dollar amount estimated by the managing general partner. The managing general partner believes the prices under the drilling and operating agreement are competitive 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 being unreasonable and disallowed as a deductible intangible drilling cost. The managing general partner does not anticipate that Atlas America Public #14-2005(A) L.P., which has a targeted final closing date of May 31, 2005 (which is not binding on the partnership), will prepay in 2005 any of its intangible drilling costs for drilling activities that will begin in 2006. However, depending primarily on when each partnership's subscription proceeds are received, the managing general partner anticipates that Atlas America Public #14-2004 L.P. will prepay in 2004 most, if not all, of its intangible drilling costs for drilling activities that will begin in 2005. In addition, the managing general partner anticipates that Atlas America Public #14-2005(B) L.P., which may close on December 31, 2005, may prepay in 2005 most, if not all, of its intangible drilling costs for drilling activities that will begin in 2006. 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. The test is: o the expenditure must be a payment rather than a refundable deposit; and o the deduction must not result in a material distortion of income taking into substantial consideration the business purpose aspects of the transaction. Each partnership will attempt to comply with the guidelines set forth in Keller with respect to any prepaid intangible drilling costs. In the year in which you invest, the drilling and operating agreement will require your partnership to prepay all of your partnership's share of the estimated intangible drilling costs and the investors' share of your partnership's estimated equipment costs for drilling and completing specified wells, the drilling of which may begin in the following year. These prepayments should not result in a loss of a current deduction for the intangible drilling costs if: o there is a legitimate business purpose for the required prepayment; o the contract is not merely a sham to control the timing of the deduction; and o there is an enforceable contract of economic substance. 96 The drilling and operating agreement will require each partnership to prepay the managing general partner's estimate of the intangible drilling costs and the investors' share of the equipment costs to drill and complete the wells specified in the drilling and operating agreement in order to enable the operator to: o begin site preparation for the wells; o obtain suitable subcontractors at the then current prices; and o insure the availability of equipment and materials. Under the drilling and operating agreement excess prepaid intangible drilling costs, if any, will not be refundable to a partnership, but instead will be applied only to intangible drilling cost overruns, if any, on the other specified wells being drilled or completed by the partnership or to intangible drilling costs to be incurred by the partnership in drilling and completing substitute wells. Under Keller, a provision for substitute wells should not result in the prepayments being characterized as refundable deposits. The likelihood that prepayments of intangible drilling costs will be challenged by the IRS on the grounds that there is no business purpose for the prepayments is increased if prepayments are not required with respect to all of the working interest in the well. The managing general partner anticipates that less than 100% of the working interest will be acquired by each partnership in one or more of its wells, and prepayments of intangible drilling costs will not be required of all owners of working interests in those wells. In the view of special counsel, however, a legitimate business purpose for the required prepayments of intangible drilling costs by the partnership may exist under the guidelines set forth in Keller, even though prepayments are not required by the drilling contractor with respect to a portion of the working interest in the wells. In addition, a current deduction for prepaid intangible drilling costs is available only if the drilling of the wells begins before the close of the 90th day after the close of the taxable year in which the prepayment was made. Under the drilling and operating agreement, the managing general partner as operator and general drilling contractor must begin drilling each of the prepaid wells no later than March 31, 2005 for Atlas America Public #14-2004 L.P. and March 31, 2006 for Atlas America Public #14-2005(B) L.P. However, the drilling of any partnership well may be delayed due to circumstances beyond the control of the managing general partner or the drilling subcontractors. These circumstances include, for example: o the unavailability of drilling rigs; o decisions of third-party operators to delay drilling the wells; o poor weather conditions; o inability to obtain drilling permits or access right to the drilling site; or o title problems; and the managing general partner will have no liability to any partnership or its investors if these types of events delay beginning the drilling of the prepaid wells past the close of the 90th day after the close of the partnership's taxable year. If the drilling of a prepaid partnership well does not begin before the close of the 90th day after the close of your partnership's taxable year in which the prepayment was made, deductions claimed by you for prepaid intangible drilling costs for the well in the year in which you invest in the partnership would be disallowed and deferred to the next taxable year when the well is actually drilled. No assurance can be given that on audit the IRS would not disallow the current deductibility of a portion or all of any prepaid intangible drilling costs under a partnership's drilling contracts, thereby decreasing the amount of the investors' deductions in the partnership for the year in which they invest in the partnership, or that the challenge would not ultimately be sustained. In the event of disallowance, the deduction for prepaid intangible drilling costs would be available in the next year when the wells are actually drilled. 97 DEPLETION ALLOWANCE Proceeds from the sale of each partnership's natural gas and oil production will constitute ordinary income. A certain portion of that income will not be taxable under the depletion allowance which permits the deduction from gross income for federal income tax purposes of either the percentage depletion allowance or the cost depletion allowance, whichever is greater. Depletion deductions generally will be treated as ordinary income if a property or your units are 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 natural gas or oil expected to be recoverable from the property and then multiplying the resultant quotient by the number of units actually sold during the year. Cost depletion cannot exceed the adjusted tax basis of the property to which it relates. Percentage depletion generally is available to taxpayers other than "integrated oil companies," which term does not include the partnerships. Percentage depletion is based on your share of your partnership's gross production income from its natural gas and oil 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 natural gas and oil 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 equivalent to 90 mcf of natural gas, per producing well on the property in the calendar year. Most, if not all, of each partnership's wells will be marginal producing wells under this definition in the Internal Revenue Code and will qualify for these potentially higher rates of percentage depletion. The rate of percentage depletion for marginal production in 2004 is 15%. This rate may fluctuate 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%. Also, percentage depletion: o may not exceed 100% of the net income from each natural gas and oil property before the deduction for depletion; and o 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. Availability of percentage depletion must be computed separately by you, and not by your partnership or for investors in your partnership 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 ("Tangible Costs") and the related depreciation deductions of each partnership generally are charged and allocated under the partnership agreement 66% to the managing general partner and 34% to you and the other investors in the partnership. However, if the total equipment costs for all of the partnership's wells that would be charged to you and the other investors exceeds an amount equal to 10% of the subscription proceeds of you and the other investors, then the excess, together with the related depreciation deductions, will be charged and allocated to the managing general partner. Most of each partnership's equipment costs will be recovered through depreciation deductions over a seven year cost recovery period, using the 200% declining balance method, with a switch to straight-line to maximize the deduction, beginning in the taxable year the equipment is "placed in service" by the partnership as discussed below. In the case of a short tax year the MACRS deduction is prorated on a 12-month basis. No distinction is made between new and used property and salvage value is disregarded. Generally only a half-year of depreciation is allowed for the year recovery property is placed in service or disposed of. Except as discussed below, smaller depreciation deductions in a partnership's early years are used for purposes of the alternative minimum tax. All of these cost recovery deductions claimed by the partnerships and their respective investors are subject to recapture as ordinary income rather than capital gain on the sale or other taxable disposition of the property or an investor's units. 98 Notwithstanding the foregoing, for federal income tax purposes Atlas America Public #14-2004 L.P., but not Atlas America Public #14-2005(A) L.P. or Atlas America Public #14-2005(B) L.P., will be entitled to an additional first-year depreciation allowance based on 50% of the adjusted basis of its "qualified" equipment costs, if any. For this purpose, the partnership's "qualified" equipment costs means its equipment costs for productive wells which are completed and made capable of production, i.e. placed in service, before January 1, 2005. Thus, this additional first-year depreciation allowance will not be available for wells placed in service in 2005, even though the investors' share of the partnership's equipment costs for the wells is prepaid in 2004, because the special rule that allows current deductions for prepaid intangible drilling costs does not apply to prepaid equipment costs. In addition, the basis of the partnership's qualified equipment will be reduced by the additional 50% first-year depreciation allowance for purposes of calculating the regular MACRS depreciation allowances beginning in 2004. Also, if you invest in Atlas America Public #14-2004 L.P. you will not incur any alternative minimum tax adjustment with respect to your share of the partnership's additional 50% first-year depreciation allowance, nor any of its other depreciation deductions for the costs of the qualified equipment it places in productive wells which are drilled, completed and placed in service in 2004, if any. LEASE ACQUISITION COSTS AND ABANDONMENT Lease acquisition costs, together with the related cost depletion deduction and any abandonment loss for lease costs, are allocated under the partnership agreement 100% to the managing general partner, which will contribute the leases to each partnership as a part of its capital contribution. TAX BASIS OF UNITS Your share of your partnership's losses is allowable only to the extent of the adjusted basis of your units at the end of the partnership's taxable year. The adjusted basis of your units will be adjusted, but not below zero, for any gain or loss to you from a sale or other taxable disposition by the partnership of a natural gas or oil property, and will be increased by your: o cash subscription payment; o share of partnership income; and o share, if any, of partnership debt. The adjusted basis of your units will be reduced by your: o share of partnership losses; o depletion deductions, but not below zero; and o cash distributions from the partnership. The reduction in your share of partnership liabilities, if any, is considered a cash distribution to you. Should cash distributions to you from your partnership exceed the tax basis of your units, taxable gain would result to you to the extent of the excess. "AT RISK" LIMITATION FOR LOSSES Subject to the limitations on "passive losses" generated by a partnership in the case of limited partners, and your basis in your units, you generally may use your share of your partnership's losses to offset income from other sources. However, generally 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" in the partnership in which you invest generally will equal the amount of money you paid for your units, reduced by any amounts you may have borrowed from persons who have an interest in the partnership, other than as a creditor, to purchase your units. Also, the amount you have "at risk" in your partnership may not include the amount of any loss that you are protected against through: o nonrecourse loans; 99 o guarantees; o stop loss agreements; or o other similar arrangements. DISTRIBUTIONS FROM A PARTNERSHIP Generally, a cash distribution from your partnership to you in excess of the adjusted basis of your units immediately before the distribution is treated as gain to you from the sale or exchange of your units to the extent of the excess. No loss can be recognized by you on these distributions. Other distributions of property and liquidating distributions by your partnership may result in taxable gain or loss to you. SALE OF THE PROPERTIES Under the Jobs and Growth Tax Relief Reconciliation Act of 2003 ("2003 Tax Act"), the maximum tax rates on a noncorporate taxpayer's adjusted net capital gain on the sale of assets held more than a year of 20%, or 10% to the extent it would have been taxed at a 10% or 15% rate if it had been ordinary income, have been reduced to 15% and 5%, respectively, for most capital assets sold or exchanged after May 5, 2003. In addition, for 2008 only, the 5% tax rate on adjusted net capital gain is reduced to 0%. The 2003 Tax Act also eliminated the former maximum tax rates of 18% and 8%, respectively, on qualified five-year gain. I.R.C. ss.1(h). The new capital gain rates also apply for purposes of the alternative minimum tax. I.R.C. ss.55(b)(3). (See "- Alternative Minimum Tax," below. However, the former tax rates are scheduled to be reinstated January 1, 2009, as if the 2003 Tax Act had never been enacted. "Adjusted net capital gain" means net capital gain, less certain types of net capital gain that are taxed a maximum rate of 28% (such as gain on the sale of most collectibles and gain on the sale of certain small business stock); or 25% (gain attributable to real estate depreciation). "Net capital gain" means the excess of net long-term gain (excess of long-term gains over long-term losses) over net short-term loss (excess of short-term gains over short-term losses). The annual capital loss limitation for noncorporate taxpayers is the amount of capital gains plus the lesser of $3,000, which is reduced to $1,500 for married persons filing separate returns, or the excess of capital losses over capital gains. Gains and losses from sales of natural gas and oil properties held for more than 12 months generally will be treated as a long-term capital gain, while a net loss will be an ordinary deduction. However, on disposition of a natural gas or oil property gain is treated as ordinary income to the extent of the lesser of: o the amounts that were deducted as intangible drilling costs rather than added to basis, plus depletion deductions that reduced the basis of the property; or o 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. In addition, all equipment depreciation deductions, and certain losses for a partnership's five most recent taxable years, if any, on previous sales of that partnership's assets, are treated as ordinary income to the extent of any gain on the sale or other taxable disposition of the property. Other gains and losses on sales of natural gas and oil properties will generally result in ordinary gains or losses. DISPOSITION OF UNITS The sale or exchange, including a purchase by the managing general partner, of all or some of your units held by you for more than 12 months generally will result in a recognition of long-term capital gain or loss. However, previous deductions for depreciation, depletion and intangible drilling costs, and your share of the partnership's "ss.751 assets" (i.e. inventory and unrealized receivables), may be recaptured as ordinary income rather than capital gain regardless of how long you have owned your units. (See "- Sale of the Properties," above.) If the units are held for 12 months or less, the gain or loss generally will be short-term gain or loss. Also, your pro rata share of your partnership's liabilities, if any, as of the date of the sale or exchange must be included in the amount realized. Therefore, the gain recognized by you may result in a tax liability to you greater than the cash proceeds, if any, received by you from the disposition. In addition to gain from a passive activity, a portion of any gain recognized by a limited partner on the sale or other taxable disposition of his units may be characterized as portfolio income under the passive activity loss rules to the extent the gain is attributable to portfolio income, e.g. interest income on investments of working capital. (See "- Limitations on Passive Activities," above.) 100 A gift of your units may result in federal and/or state income tax and gift tax liability to you. Also, interests in different partnerships do not qualify for tax-free like-kind exchanges. Other dispositions of your units may or may not result in recognition of taxable gain. However, no gain should be recognized by an investor general partner on the conversion of his investor general partner units to limited partner units so long as there is no change in his share of his partnership's liabilities or certain partnership assets as a result of the conversion. In addition, if you sell or exchange all or some of your units you are required by the Internal Revenue Code to notify your partnership within 30 days or by January 15 of the following year, if earlier and the partnership will then report certain tax information regarding the transfer of the units to the IRS, including your share of the partnership's ss.751 assets which are subject to recapture as ordinary income as discussed above. If you die, or sell or exchange all of your Units, the taxable year of your partnership will close with respect to you, but not the remaining investors, on the date of death, sale or exchange, with a proration of partnership items for the partnership's taxable year. If you sell less than all of your units, the partnership's taxable year will not terminate with respect to you, but your proportionate share of the partnership's items of income, gain, loss and deduction will be determined by taking into account your varying interests in the partnership during the taxable year. You are urged to consult with your own tax advisor before you make any disposition of your units, including purchase of the units by the managing general partner. ALTERNATIVE MINIMUM TAX With limited exceptions, you must pay an alternative minimum tax if it exceeds your regular federal income tax for the year. Alternative minimum taxable income generally is taxable income, plus or minus various adjustments, plus tax preference items. The tax rate for noncorporate taxpayers is 26% for the first $175,000, $87,500 for married individuals filing separately, of a taxpayer's alternative minimum taxable income in excess of the exemption amount; and additional alternative minimum taxable income is taxed at 28%. However, the regular tax rates on capital gains also will apply for purposes of the alternative minimum tax. (See "- Sale of the Properties," above.) Subject to the phase-out provisions summarized below, the exemption amounts for 2004 are $58,000 for married individuals filing jointly, $40,250 for single persons and $29,000 for married individuals filing separately. For years beginning after 2004, these exemption amounts are scheduled to decrease to $45,000 for married individuals filing jointly, $33,750 for single persons, and $22,500 for married individuals filing separately. As of the date of this prospectus, the U.S. House of Representatives had passed a bill that would extend the 2004 exemption amounts to 2005 and index them for inflation in following years. Whether that bill or other relief for taxpayers from the alternative minimum tax will become law in 2005 is uncertain. (See "- Changes in the Law," below.) The exemption amount for estates and trusts is $22,500 in 2004 and subsequent years. The exemption amounts are reduced by 25% of alternative minimum taxable income in excess of: o $150,000, in the case of married individuals filing a joint return and surviving spouses - the $58,000 exemption amount is completely phased out when alternative minimum taxable income is $382,000 or more, and the $45,000 amount phases out completely at $330,000; o $112,500, in the case of unmarried individuals other than surviving spouses - the $40,250 exemption amount is completely phased out when alternative minimum taxable income is $273,500 or more, and the $33,750 amount phases out completely at $247,500; and o $75,000, in the case of married individuals filing a separate return - the $29,000 exemption amount is completely phased out when alternative minimum taxable income is $191,000 or more and the $22,500 amount phases out completely at $165,000. In addition, in 2004 the alternative minimum taxable income of married individuals filing separately is increased by the lesser of $29,000 ($22,500 after 2004) or 25% of the excess of the person's alternative minimum taxable income (determined without regard to this provision) over $191,000 ($165,000 after 2004). 101 Some of the principal adjustments to taxable income that are used to determine alternative minimum taxable income include: o Depreciation deductions may not exceed deductions computed using the 150% declining balance method, except as discussed above in "- Depreciation - Modified Accelerated Cost Recovery System ("MACRS")" with respect to "qualified" equipment costs of wells placed in service in 2004, if any, by Atlas America Public #14-2004 L.P. o Miscellaneous itemized deductions are not allowed. o Medical expenses are deductible only to the extent they exceed 10% of adjusted gross income. o State and local property and income taxes are not deductible. o Interest deductions are restricted. o The standard deduction and personal exemptions are not allowed. o Only some types of operating losses are deductible. o Different rules under the Internal Revenue Code apply to incentive stock options that may require earlier recognition of income. The principal tax preference items that must be added to taxable income for alternative minimum tax purposes include: o Certain excess intangible drilling costs, as discussed below. o Tax-exempt interest earned on certain private activity bonds. For taxpayers other than "integrated oil companies" as that term is defined in "- Intangible Drilling Costs," above, which does not include the partnerships, the 1992 National Energy Bill repealed: o the preference for excess intangible drilling costs; and o the excess percentage depletion preference for natural gas and oil. The repeal of the excess intangible drilling costs preference, however, under current law may not result in more than a 40% reduction in the amount of the taxpayer's 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 natural gas and oil properties. Net natural gas and oil income is determined for this purpose without subtracting excess intangible drilling costs. Excess intangible drilling costs is the regular intangible drilling costs deduction minus the amount that would have been deducted under 120-month straight-line amortization, or, at the taxpayer's election, under the cost depletion method. There is no preference item for costs of nonproductive wells. Also, you and the other investors in a partnership may separately elect under ss.59(e) of the Code to capitalize all or part of your share of the partnership's intangible drilling costs and deduct the costs ratably over a 60-month period beginning with the month in which the costs were paid or incurred by the partnership. This election also applies for regular tax purposes and can be revoked only with the IRS' consent. Making this election, therefore, generally will result in the following consequences to you: 102 o your regular tax deduction for intangible drilling costs in the year in which you invest will be reduced because you must spread the deduction for the amount of intangible drilling costs which you elect to capitalize over the 60-month amortization period; and o the capitalized intangible drilling costs will not be treated as a preference that is included in your alternative minimum taxable income. Other than intangible drilling costs as discussed above, the principal tax item that may have an impact on your alternative minimum taxable income as a result of investing in a partnership is depreciation of the partnership's equipment. Except for wells placed in service in 2004 by Atlas America Public #14-2004 L.P., if any, as noted above, if you invest in that partnership, your cost recovery deductions for regular income tax purposes generally will be computed using the 200% declining balance method rather than the 150% declining balance method used for alternative minimum tax purposes. This means that in the early years of a partnership your depreciation deductions from the partnership generally will be smaller for alternative minimum tax purposes when compared to the partnership's depreciation deductions for regular income tax purposes on the same equipment. The rules relating to the alternative minimum tax for corporations are different than those summarized above. All prospective investors contemplating purchasing units in a partnership are urged to consult with their own personal tax advisors as to the likelihood of them incurring or increasing any alternative minimum tax liability because of an investment in a partnership. LIMITATIONS ON DEDUCTION OF INVESTMENT INTEREST Investment interest expense is deductible by a noncorporate taxpayer only to the extent of net investment income each year, with an indefinite carryforward of disallowed amounts. An investor general partner's share of any interest expense incurred by the partnership in which he invests before his investor general partner units are converted to limited partner units will be subject to the investment interest limitation. In addition, the investor general partner's share of the partnership's income and losses, including the deduction for intangible drilling costs, will be considered to be investment income and losses. Thus, for example, a loss allocated to an investor general partner from the partnership in the year in which he invests in the partnership as a result of the deduction for intangible drilling costs will reduce his net investment income and may reduce or eliminate the deductibility of his investment interest expense, if any, in that taxable year, with the disallowed portion to be carried forward to the next taxable year. These rules, however, do not apply to partnership income or expense subject to the passive activity loss limitations for limited partners. ALLOCATIONS The partnership agreement allocates to each investor his share of his partnership's income, gains, losses and deductions, including the deductions for intangible drilling costs and depreciation. Your capital account in the partnership in which you invest will be adjusted to reflect your share of these allocations and your capital account, as adjusted, will be given effect in distributions made to you on liquidation of the partnership or your interest in the partnership. Generally, your capital account in the partnership in which you invest will be: o increased by the amount of money you contribute to the partnership and allocations to you of income and gain; and o decreased by the value of property or cash distributed to you by the partnership and allocations to you of loss and deductions by the partnership. It should be noted that your share of your partnership's items of income, gain, loss, and deduction must be taken into account by you whether or not you receive any cash distributions from the partnership. Your share of partnership revenues applied by your partnership 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 on taxable income from your partnership for a particular year in excess of any cash distributions from the partnership to you with respect to that year. To the extent a partnership has cash available for distribution, however, it is the managing general partner's policy that partnership cash distributions will not be less than the managing general partner's estimate of the investors' income tax liability with respect to that partnership's income. 103 If any allocation under the partnership agreement is not recognized for federal income tax purposes, your share of the items subject to that allocation generally will be determined in accordance with your interest in the partnership in which you invest, determined by considering all of the relevant facts and circumstances. To the extent the deductions allocated by the partnership agreement exceed deductions which would be allowed under a reallocation by the IRS, you may incur a greater tax burden. PARTNERSHIP BORROWINGS Under the partnership agreement the managing general partner and its affiliates may make loans to the partnerships. The use of partnership revenues taxable to you to repay borrowings by your partnership 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 OFFERING COSTS Expenses connected with the sale of the units in the partnerships, including the dealer-manager fee and sales commissions paid to the dealer-manager which are charged under the partnership agreement 100% to the managing general partner as organization and offering costs, are not deductible. Although certain organization expenses of each partnership may be amortized over a period of not less than 60 months, these expenses also will be paid by the managing general partner as part of each partnership's organization and offering costs. Thus, any related deductions, which the managing general partner does not anticipate will be material in amount as compared to the amount of the total subscription proceeds in any partnership, will be allocated to the managing general partner. TAX ELECTIONS Although each partnership may elect to adjust the basis of its property (other than cash) on the transfer of a unit in the partnership by sale or exchange or on the death of an investor, and on the distribution of property by the partnership to a partner, the managing general partner does not intend to make this election for any of the partnerships. The general effect of this election is that transferees of the units are treated, for purposes of depreciation and gain, as though they had acquired a direct interest in the partnership assets and the partnership is treated for these purposes, on 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. As of the date of this prospectus several bills were pending in Congress that proposed to make the ss.754 election mandatory for all partnerships. If the ss.754 election does become mandatory, the primary effect on your partnership, other than the federal income tax consequences summarized above, would be an increase in its administrative and accounting expenses to make the required basis adjustments to its properties and separately account for those adjustments after they are made. In this regard, the partnerships generally will not make in-kind property distributions to their respective investors, and the units have no readily available market and are subject to substantial restrictions on their transfer. (See "Transferability of Units - Restrictions on Transfers Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement.") These factors will tend to limit the additional expense to your partnership if the ss.754 election applies to it. Also, certain "start-up expenditures" must be capitalized and amortized over a 60-month period. If it is ultimately determined that any of a partnership's expenses constituted start-up expenditures and not deductible business expenses, the partnership's deductions for those expenses would be deferred over the 60-month period. TERMINATION OF A PARTNERSHIP A partnership will be considered as terminated for federal income tax purposes if within a 12 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 to the extent that money regarded as distributed to you by your partnership exceeds the adjusted basis of your units. The conversion of investor general partner units to limited partner units, however, will not terminate a partnership. Also, due to the restrictions on transfers of units in the partnership agreement, the managing general partner does not anticipate that any of the partnerships will ever be considered as terminated for this reason for federal income tax purposes. 104 LACK OF REGISTRATION AS A TAX SHELTER An organizer of a "tax shelter" must obtain an identification number which must be included on the individual federal income tax returns of investors in the tax shelter. For this purpose, a "tax shelter" includes an investment 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. In this regard, the managing general partner has determined that none of the partnerships has a tax shelter ratio greater than 2 to 1. Accordingly, the managing general partner does not intend to register any of the partnerships with the IRS as a tax shelter. If it is subsequently determined by the IRS or the courts that the partnership in which you invest 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 a tax shelter registration number for your partnership on your individual federal income 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 units. However, special counsel has expressed the opinion that none of the partnerships is required to register with the IRS as a tax shelter. This opinion is based in part on the managing general partner's representations that none of the partnerships has a tax shelter ratio greater than 2 to 1 and each partnership will be operated as described in this prospectus. 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. If requested by the IRS, a partnership may be required to identify its investors and give the IRS certain information concerning each investor's investment in the partnership and the tax benefits of the partnership to the investors. TAX RETURNS AND IRS AUDITS IN GENERAL. The tax treatment of all partnership items generally is determined at the partnership, rather than the partner, level; and the partners generally are required to treat partnership items on their individual federal income tax returns in a manner which is consistent with the treatment of the partnership items on the partnership's federal information income tax 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 you and the other investors attributable to a partnership item may be extended by agreement between the IRS and the managing general partner, which will serve as each partnership's representative (the "Tax Matters Partner") in all administrative and judicial tax proceedings conducted at the partnership level. The managing general partner generally may enter into a settlement on behalf of, and binding on, any investor owning less than a 1% profits interest in a partnership 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 federal income tax returns by the IRS. The managing general partner does not anticipate that the partnerships 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. All expenses of any proceedings involving the managing general partner as Tax Matters Partner, which might be substantial, will be paid for by the partnership being audited. The managing general partner, however, is not obligated to contest adjustments made by the IRS. The managing general partner, as Tax Matters Partner, will notify you and the other investors in a partnership of any IRS audits or other tax proceedings, and will provide you any other information regarding the proceedings as may be required by the partnership agreement or law. TAX RETURNS. Your individual income tax returns are your responsibility. The partnership in which you invest will provide you with the tax information applicable to your investment in the partnership necessary to prepare your tax returns. PENALTIES AND INTEREST IN GENERAL. Interest is charged on underpayments of federal income tax and various penalties are included in the Internal Revenue Code. 105 PENALTY FOR NEGLIGENCE OR DISREGARD OF RULES OR REGULATIONS. If any portion of an underpayment of federal income tax is attributable to negligence or disregard of IRS rules or regulations, 20% of that portion is added to the tax. Negligence is strongly indicated if you fail to treat partnership items on your individual federal income tax return in a manner that is consistent with the treatment of those items on your partnership's federal information income tax return or to notify the IRS of the inconsistency. VALUATION MISSTATEMENT PENALTY. There is an addition to federal income 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: o the value or adjusted basis of any property claimed on a return is 200% or more of the correct amount; or o 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%. SUBSTANTIAL UNDERSTATEMENT PENALTY. There is also an addition to federal income 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: o 10% of the tax required to be shown on the return; or o $5,000. The amount of any understatement generally will be reduced to the extent it is attributable to the tax treatment of an item: o supported by substantial authority; or o adequately disclosed on the taxpayer's individual federal income return and there was a reasonable basis for the tax treatment. However, in the case of "tax shelters," which as defined by the Internal Revenue Code for this purpose includes each partnership, the understatement may be reduced by a taxpayer, other than a corporation, only if the tax treatment of an item attributable to a tax shelter was supported by substantial authority and the taxpayer establishes that he reasonably believed that the tax treatment claimed was more likely than not the proper treatment. PROFIT MOTIVE, IRS ANTI-ABUSE RULE AND JUDICIAL DOCTRINES. Your ability to deduct your share of your partnership's losses could be lost if the partnership lacks the appropriate profit motive. There is a presumption under the Internal Revenue Code that an activity is engaged in for profit if, in any three of five consecutive taxable years, the gross income derived from the activity exceeds the deductions attributable to the activity. Thus, if your partnership fails to show a profit in at least three 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. Also, 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 under Treas. Reg. ss.1.701-2 to remedy the abuse. Finally, under potentially relevant judicial doctrines including the step transaction, business purpose, economic substance, substance over form, and sham transaction doctrines, tax deductions from a transaction will be disallowed if the transaction has no economic substance apart from the tax benefits. 106 With respect to these issues, special counsel has given its opinion that the partnerships will possess the requisite profit motive, and the IRS anti-abuse rule in Treas. Reg ss.1.701-2 and the potentially relevant judicial doctrines listed above, will not have a material adverse effect on the tax consequences of an investment in a partnership by a typical investor as described in special counsel's opinions. These opinions are based in part on the results of the previous partnerships sponsored by the managing general partner as set forth in "Prior Activities" and the managing general partner's representations. These representations include that each partnership will be operated as described in this prospectus, see "Management" and "Proposed Activities," and the principal purpose of each partnership is to locate, produce and market natural gas and oil on a profitable basis, apart from tax benefits. These representations are supported by the geological evaluations and the other information for the partnerships' proposed drilling areas and the specific prospects proposed to be drilled by Atlas America Public #14-2004 L.P. included in Appendix A to this prospectus, which when supplemented or amended will cover a portion of the prospects proposed to be drilled by each of the other partnerships when units in those partnerships are offered to potential investors. STATE AND LOCAL TAXES Each partnership will operate in states and localities which may impose a tax on its assets or income, or on its investors. The states also may impose income tax withholding requirements on the partnership in which you invest on your share of the partnership's income whether distributed to you or not. Deductions which are available to you for federal income tax purposes, such as the additional 50% first-year depreciation deduction discussed in "- Depreciation - Modified Accelerated Cost Recovery System ("MACRS") above, which may be available to investors in Atlas America Public #14-2004 L.P. for a portion of its wells, may not be available for state or local income tax purposes. Your share of the net income or net loss of the partnership in which you invest generally must be included in determining your reportable income for state or local tax purposes in the jurisdiction in which you reside. To the extent that you pay tax to another state because of partnership operations within that state, you may be entitled to a deduction or credit against tax owed to your state of residence with respect to the same income. To the extent that the partnership operates in certain jurisdictions, state or local estate or inheritance taxes may be payable on the death of an investor in addition to taxes imposed by his own domicile. You are urged to consult with your own tax advisors concerning the possible effect of various state and local taxes on your personal tax situation resulting from an investment in a partnership. SEVERANCE AND AD VALOREM (REAL ESTATE) TAXES Each partnership may incur various ad valorem or severance taxes imposed by state or local taxing authorities on its natural gas and oil wells and/or natural gas and oil production from the wells. SOCIAL SECURITY BENEFITS AND SELF-EMPLOYMENT TAX A limited partner's share of income or loss from a 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 a partnership will constitute "net earnings from self-employment" for these purposes. The ceiling for social security tax of 12.4% in 2004 is $87,900 and the ceiling for 2005 is not yet known. There is no ceiling for medicare tax of 2.9%. Self-employed individuals can deduct one-half of their self-employment tax. FARMOUTS Under a farmout by a partnership, if a property interest, other than an interest in the drilling unit assigned to the partnership well in question, is earned by the farmee (anyone other than the partnership) from the farmor (the partnership) as a result of the farmee drilling or completing the well, then the farmee must recognize income equal to the fair market value of the outside interest earned, and the farmor must recognize gain or loss on a deemed sale equal to the difference between the fair market value of the outside interest and the farmor's tax basis in the outside interest. Neither the farmor nor the farmee would have received any cash to pay the tax. The managing general partner will attempt to eliminate or reduce any gain to a partnership from a farmout, if any. However, if the IRS claims that a farmout by a partnership results in taxable income to the partnership and its position is ultimately sustained, the investors in that partnership would be required to include their share of the resulting taxable income on their personal income tax returns, even though the partnership and its investors received no cash from the farmout. 107 FOREIGN PARTNERS Each partnership generally will be required to withhold and pay income tax to the IRS at the highest rate under the Internal Revenue Code applicable to partnership income allocable to its foreign investors, even if no cash distributions are made to them. In the event of overwithholding a investor partner must file a United States tax return to obtain a refund. Under the Internal Revenue Code, for withholding purposes a foreign investor generally means an investor who is a nonresident alien individual or a foreign corporation, partnership, trust or estate, if the investor has not certified to his partnership the investor's nonforeign status. ESTATE AND GIFT TAXATION There is no federal tax on lifetime or testamentary transfers of property between spouses. The gift tax annual exclusion in 2004 is $11,000 per donee, which will be adjusted in subsequent years for inflation. Under the Economic Growth and Tax Relief Reconciliation Act of 2001 ("the 2001 Tax Act"), the maximum estate and gift tax rate of 48% in 2004 will be reduced in stages until it is 45% from 2007 to 2009. Estates of $1.5 million in 2004, which increases in stages to $3.5 million by 2009, or less generally are not subject to federal estate tax. Under the 2001 Tax Act, the federal estate tax is scheduled to be repealed in 2010, and the maximum gift tax rate in 2010 will be 35%. In 2011 the federal estate and gift taxes are scheduled to be reinstated under the rules in effect before the 2001 Tax Act was enacted. CHANGES IN THE LAW Your investment in a partnership may be affected by changes in the tax laws. (See "- Tax Elections," above.) For example, in 2003, the top four federal income tax brackets for individuals were reduced through December 31, 2010, including reducing the top bracket to 35% from 38.6%. The lower federal income tax rates will reduce to some degree the amount of taxes you save by virtue of your share of your partnership's deductions for intangible drilling costs, depletion and depreciation. However, the lower federal income tax rates also will reduce the amount of federal income tax liability incurred by you on your share of the net income of your partnership. There is no assurance that the federal income tax rates discussed above will not be changed again before 2011. SUMMARY OF PARTNERSHIP AGREEMENT The rights and obligations of the managing general partner and you and the other investors are governed by the form of partnership agreement attached as Exhibit (A) to this prospectus. You are urged to not invest in a partnership without first thoroughly reviewing the partnership agreement. The following is a summary of the material provisions in the partnership agreement that are not covered elsewhere in this prospectus. Thus, this prospectus summarizes all of the material provisions of the partnership agreement. LIABILITY OF LIMITED PARTNERS Each partnership will be governed by the Delaware Revised Uniform Limited Partnership Act. If you invest as a limited partner, then generally you will not be liable to third-parties for the obligations of your partnership unless you: o also invest as an investor general partner; o take part in the control of the partnership's business in addition to the exercise of your rights and powers as a limited partner; or o fail to make a required capital contribution to the extent of the required capital contribution. In addition, you may be required to return any distribution you receive if you knew at the time the distribution was made that it was improper because it rendered the partnership insolvent. AMENDMENTS Amendments to the partnership agreement of a partnership may be proposed in writing by: 108 o the managing general partner and adopted with the consent of investors whose units equal a majority of the total units in the partnership; or o investors whose units equal 10% or more of the total units in the partnership and adopted by an affirmative vote of investors whose units equal a majority of the total units in the partnership. The partnership agreement of each partnership may also be amended by the managing general partner without the consent of the investors for certain limited purposes. However, an amendment that materially and adversely affects the investors can only be made with the consent of the affected investors. NOTICE The following provisions apply regarding notices: o when the managing general partner gives you and other investors notice it begins to run from the date of mailing the notice and is binding even if it is not received; o the notice periods are frequently quite short, a minimum of 22 calendar days, and apply to matters that may seriously affect your rights; and o if you fail to respond in the specified time to the managing general partner's second request for approval of or concurrence in a proposed action, then you will conclusively be deemed to have approved the action unless the partnership agreement expressly requires your affirmative approval. VOTING RIGHTS Other than as set forth below, you generally will not be entitled to vote on any partnership matters at any partnership meeting. However, at any time investors whose units equal 10% or more of the total units in a partnership may call a meeting to vote, or vote without a meeting, on the matters set forth below without the concurrence of the managing general partner. On the matters being voted on you are entitled to one vote per unit or if you own a fractional unit that fraction of one vote equal to the fractional interest in the unit. Investors whose units equal a majority of the total units in a partnership may vote to: o dissolve the partnership; o remove the managing general partner and elect a new managing general partner; o elect a new managing general partner if the managing general partner elects to withdraw from the partnership; o remove the operator and elect a new operator; o approve or disapprove the sale of all or substantially all of the partnership assets; o cancel any contract for services with the managing general partner, the operator, or their affiliates without penalty on 60 days notice; and o amend the partnership agreement; provided however, any amendment may not: o without the approval of you or the managing general partner increase the duties or liabilities of you or the managing general partner or increase or decrease the profits or losses or required capital contribution of you or the managing general partner; or o without the unanimous approval of all investors in the partnership affect the classification of partnership income and loss for federal income tax purposes. 109 The managing general partner, its officers, directors, and affiliates may also subscribe for units in each partnership on a discounted basis, and they may vote on all matters other than: o the issues set forth above concerning removing the managing general partner and operator; and o any transaction between the managing general partner or its affiliates and the partnership. Any units owned by the managing general partner and its affiliates will not be included in determining the requisite number of units necessary to approve any partnership matter on which the managing general partner and its affiliates may not vote or consent. ACCESS TO RECORDS You will have access to all records of your partnership at any reasonable time on adequate notice. However, logs, well reports, and other drilling and operating data may be kept confidential for reasonable periods of time. Your ability to obtain the list of investors is subject to additional requirements set forth in the partnership agreement. WITHDRAWAL OF MANAGING GENERAL PARTNER After 10 years the managing general partner may voluntarily withdraw as managing general partner of a partnership for any reason by giving 120 days' written notice to you and the other investors in the partnership. Although the withdrawing managing general partner is not required to provide a substitute managing general partner, a new managing general partner may be substituted by the affirmative vote of investors whose units equal a majority of the total units in the partnership. If the investors, however, choose not to continue the partnership and select a substitute managing general partner, then the partnership would terminate and dissolve which could result in adverse tax and other consequences to you. Also, subject to a required participation of not less than 1% of each partnership's revenues, the managing general partner may withdraw a property interest in the form of a working interest in the partnership's wells equal to or less than its revenue interest if the withdrawal is: o to satisfy the bona fide request of its creditors; or o approved by investors in the partnership whose units equal a majority of the total units. RETURN OF SUBSCRIPTION PROCEEDS IF FUNDS ARE NOT INVESTED IN TWELVE MONTHS Although the managing general partner anticipates that each partnership will spend all of its subscription proceeds soon after the offering of the partnership closes, each partnership will have 12 months in which to use or commit funds to drilling activities. If within the 12-month period the partnership has not used or committed for use all the subscription proceeds, then the managing general partner will distribute the remaining subscription proceeds to you and the other investors in the partnership in accordance with your subscription proceeds as a return of capital. SUMMARY OF DRILLING AND OPERATING AGREEMENT The managing general partner will serve as the operator under the drilling and operating agreement, Exhibit (II) to the partnership agreement. The operator may be replaced at any time on 60 days' advance written notice by the managing general partner acting on behalf of a partnership on the affirmative vote of investors whose units equal a majority of the total units in the partnership. You are urged not to invest in a partnership without first thoroughly reviewing the drilling and operating agreement. The following is a summary of the material provisions in the drilling and operating agreement that are not covered elsewhere in this prospectus. Thus, this prospectus summarizes all of the material provisions of the drilling and operating agreement. The drilling and operating agreement includes a number of material provisions, including, without limitation, those set forth below. 110 o The operator's right to resign after five years. o The operator's right beginning one year 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 one year. o 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 a partnership. o The prescribed insurance coverage to be maintained by the operator. o Limitations on the operator's authority to incur extraordinary costs with respect to producing wells in excess of $5,000 per well. o 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. o The limitation of the operator's liability to a partnership except for the operator's: o violations of law; o negligence or misconduct by it, its employees, agents or subcontractors; or o breach of the drilling and operating agreement. o The excuse for nonperformance by the operator due to force majeure which generally means acts of God, catastrophes and other causes which preclude the operator's performance and are beyond its control. (See "Material Federal Income Tax Consequences - Drilling Contracts.") REPORTS TO INVESTORS Under the partnership agreement for each partnership you and certain state securities commissions will be provided the reports and information set forth below for your partnership, which your partnership will pay as a direct cost. o Beginning with the calendar year in which your partnership closes, you will be provided an annual report within 120 days after the close of the calendar year, and beginning with the following calendar year, a report within 75 days after the end of the first six months of its calendar year, containing at least the following information. o Audited financial statements of the partnership prepared on an accrual basis in accordance with generally accepted accounting principles with a reconciliation for information furnished for income tax purposes. Independent certified public accountants will audit the financial statements to be included in the annual report, but semiannual reports will not be audited. o 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 reimbursement for administrative costs bears to annual partnership revenues. In this regard, the independent certified public accountant will provide written attestation annually, which will be included in the annual report, that the method used to make allocations was consistent with the method described inss.4.04(a)(2)(c) of the partnership agreement and that the total amount of costs allocated did not materially exceed the amounts actually incurred by the managing general partner. 111 If the managing general partner subsequently decides to allocate expenses in a manner different from that described in ss.4.04(a)(2)(c) of the partnership agreement, then the change must be reported to you and the other investors with an explanation of the reason for the change and the basis used for determining the reasonableness of the new allocation method. o A description of each prospect owned by the partnership, including the cost, location, number of acres, and the interest. o A list of the wells drilled or abandoned by the partnership indicating: o whether each of the wells has or has not been completed; and o a statement of the cost of each well completed or abandoned. o A description of all farmouts, farmins, and joint ventures. o A schedule reflecting: o the total partnership costs; o the costs paid by the managing general partner and the costs paid by the investors; o the total partnership revenues; and o the revenues received or credited to the managing general partner and the revenues received or credited to you and the other investors. o On request the managing general partner will provide you the information specified by Form 10-Q (if that report is required to be filed with the SEC) within 45 days after the close of each quarterly fiscal period. Also, this information is available at the SEC website www.sec.gov. o By March 15 of each year you will receive the information that is required for you to file your federal and state income tax returns. o Beginning with the second calendar year after your partnership closes, and every year thereafter, you will receive a computation of the partnership's total natural gas and oil proved reserves and its dollar value. The reserve computations will be based on engineering reports prepared by the managing general partner and reviewed by an independent expert. PRESENTMENT FEATURE Beginning with the fifth calendar year after your partnership closes you and the other investors in your partnership may present your units to the managing general partner to purchase your units. However, you are not required to offer your units to the managing general partner, and you may receive a greater return if you retain your units. The managing general partner will not purchase less than one unit unless the fractional unit represents your entire interest. The managing general partner has no obligation and does not intend to establish a reserve to satisfy the presentment obligation and may immediately suspend its purchase obligation by notice to you if it determines, in its sole discretion, that it: o does not have the necessary cash flow; or o cannot borrow funds for this purpose on terms it deems reasonable. 112 If fewer than all units presented at any time are to be purchased by the managing general partner, then the units to be purchased will be selected by lot. The managing general partner's obligation to purchase the units presented may be discharged for its benefit by a third-party or an affiliate. If you sell your unit it will be transferred to the party who pays for it, and you will be required to deliver an executed assignment of your unit along with any other documents that the managing general partner requests. Your presentment is subject to the following conditions: o the managing general partner will not purchase more than 5% of the units in a partnership in any calendar year; o the presentment must be within 120 days of the partnership reserve report discussed below; o in accordance with Treas. Reg.ss.1.7704-1(f) the purchase may not be made by the managing general partner until at least 60 calendar days after you notify the partnership in writing of your intent to present your unit; and o the purchase will not be considered effective until the presentment price has been paid to you in cash. The amount attributable to a partnership's natural gas and oil reserves will be determined based on the last reserve report. Beginning with the second calendar year after your partnership closes and every year thereafter, the managing general partner will estimate the present worth of future net revenues attributable to your partnership's interest in proved reserves. In making this estimate, the managing general partner will use: o a 10% discount rate; o a constant oil price; and o base natural gas prices on the existing natural gas contracts at the time of the presentment. Your presentment price will be based on your share of your partnership's net assets and liabilities as described below, based on the ratio that the number of your units bears to the total number of units in your partnership. The presentment price will include the sum of the following partnership items: o an amount based on 70% of the present worth of future net revenues from the proved reserves determined as described above; o cash on hand; o prepaid expenses and accounts receivable, less a reasonable amount for doubtful accounts; and o 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: o an amount equal to all debts, obligations, and other liabilities, including accrued expenses; and o 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, natural gas, or 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. 113 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: o 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 o any of the following occurring before payment of the presentment price to you; o changes in well performance; o increases or decreases in the market price of oil, natural gas, or other minerals; o revision of regulations relating to the importing of hydrocarbons; and o changes in income, ad valorem, and other tax laws such as material variations in the provisions for depletion; and o similar matters. As of January 1, 2004, approximately 80 units have been presented to the managing general partner for purchase in its previous 46 limited partnerships. TRANSFERABILITY OF UNITS RESTRICTIONS ON TRANSFER IMPOSED BY THE SECURITIES LAWS, THE TAX LAWS AND THE PARTNERSHIP AGREEMENT Your ability to sell or otherwise transfer your units in your partnership is restricted by the securities laws, the tax laws, and the partnership agreement as described below. Also, the transfer may create negative tax consequences to you as described in "Material Federal Income Tax Consequences - Disposition of Units." First, 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: o the termination of your partnership for tax purposes; or o your partnership being treated as a "publicly-traded" partnership for tax purposes. Second, under the partnership agreement transfers are subject to the following limitations: o except as provided by operation of law, the partnership will recognize the transfer of only one or more whole units unless you own less than a whole unit, in which case your entire fractional interest must be transferred; o the costs and expenses associated with the transfer must be paid by the person transferring the unit; o the form of transfer must be in a form satisfactory to the managing general partner; and o the terms of the transfer must not contravene those of the partnership agreement. Your transfer of a unit will not relieve you of your responsibility for any obligations related to the units under the partnership agreement. Also, the transfer does not grant rights under the partnership agreement as among your transferees to more than one party unanimously designated by the transferees to the managing general partner. Finally, the transfer of a unit does not require an accounting by the managing general partner. Any transfer when the assignee of the unit does not become a substituted partner as described below in "- Conditions to Becoming a Substitute Partner," will be effective as of: 114 o midnight of the last day of the calendar month in which it is made; or o at the managing general partner's election 7:00 A.M. of the following day. Finally, you will not be able to sell, assign, pledge, hypothecate, or transfer your unit unless there is an opinion of counsel acceptable to the managing general partner that the registration and qualification under any applicable federal or state securities laws are not required. CONDITIONS TO BECOMING A SUBSTITUTE PARTNER On a transfer unless an assignee becomes a substituted partner in accordance with the provisions set forth below, he will not be entitled to any of the rights granted to a partner under the 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. The conditions to become a substitute partner are as follows: o the assignor gives the assignee the right; o the assignee pays all costs and expenses incurred in connection with the substitution; and o the assignee executes and delivers the instruments necessary to establish that a legal transfer has taken place and to confirm his agreement to be bound by all terms and provisions of the partnership agreement. A substitute partner is entitled to all of the rights of full ownership of the assigned units, including the right to vote. Each partnership will amend its records at least once each calendar quarter to effect the substitution of substituted partners. PLAN OF DISTRIBUTION COMMISSIONS The units in each partnership will be offered on a "best efforts" basis by Anthem Securities, which is an affiliate of the managing general partner, acting as dealer-manager 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. Bryan Funding, Inc., a member of the NASD, will serve as dealer-manager for this offering in the states of Minnesota and New Hampshire, and will receive the same compensation as Anthem Securities for sales in those states. The term "dealer-manager" as used in this prospectus includes both Anthem Securities, Inc. and Bryan Funding, Inc. The dealer-manager will manage and oversee the offering of the units as described above. Best efforts generally means that the dealer-manager and selling agents will not guarantee that a certain number of units will be sold. Units may also be sold by the officers and directors of the managing general partner in those states where they are licensed or exempt from licensing. Messrs. Kotek, Atkinson and Hollander, Ms. Bleichmar and Ms. Black, who are associated with Anthem Securities, will not make any offers or sales under the SEC safe harbor from broker/dealer registration provided by SEC Rule 3a4-1 promulgated under the Securities Exchange Act of 1934 (the "Act"), although they may do so as associated persons of Anthem Securities. Also, all offers and sales of units by the managing general partner's remaining officers and directors will be made under the SEC safe harbor from broker/dealer registration provided by Rule 3a4-1. In this regard, none of the remaining officers and directors of the managing general partner: o is subject to a statutory disqualification, as that term is defined in Section 3(a)(39) of the Act, at the time of his participation; o is compensated in connection with his participation by the payment of commissions or other remuneration based either directly or indirectly on transactions in securities; and 115 o is at the time of his participation an associated person of a broker or dealer. Also, each of the remaining officers and directors: o performs, or is intended primarily to perform at the end of the offering, substantial duties for or on behalf of the managing general partner otherwise than in connection with transactions in securities; o was not a broker or dealer, or an associated person of a broker or dealer, within the preceding 12 months; and o will not participate in selling an offering of securities for any issuer more than once every 12 months, with the understanding that for securities issued pursuant to Rule 415 under Securities Act of 1933, the 12 month period begins with the last sale of any security included within one Rule 415 registration. Subject to the exceptions described below, the dealer-manager will receive on each unit sold: o a 2.5% dealer-manager fee; o a 7% sales commission; o an up to .5% reimbursement of the selling agent's bona fide accountable due diligence expenses; and o a .5% accountable reimbursement for permissible non-cash compensation. Under Rule 2810 of the NASD Conduct Rules, non-cash compensation means any form of compensation received in connection with the sale of the units that is not cash compensation, including but not limited to merchandise, gifts and prizes, travel expenses, meals and lodging. Permissible non-cash compensation includes the following: o an accountable reimbursement for training and education meetings for associated persons of the selling agents; o gifts that do not exceed $100 per year and are not preconditioned on achievement of a sales target; o an occasional meal, a ticket to a sporting event or the theater, or comparable entertainment which is neither so frequent nor so extensive as to raise any question of propriety and is not preconditioned on achievement of a sales target; and o contributions to a non-cash compensation arrangement between a selling agent and its associated persons, provided that neither the managing general partner nor the dealer-manager directly or indirectly participates in the selling agent's organization of a permissible non-cash compensation arrangement. All of the reimbursement of the selling agents' bona fide accountable due diligence expenses and generally all of the 7% sales commission will be reallowed to the selling agents. With respect to the up to .5% reimbursement of a selling agent's bona fide accountable due diligence expenses, any bill presented by a selling agent to the dealer-manager for reimbursement of costs associated with its due diligence activities must be for actual costs, including overhead, incurred by the selling agent and may not include a profit margin. It is the responsibility of the managing general partner and the dealer-manager to ensure compliance with the above guideline. Although the dealer-manager is not required to obtain an itemized expense statement before paying out due diligence expenses, any bill for due diligence submitted by the selling agent to the dealer-manager must be based on the selling agent's actual expenses incurred in conducting due diligence. If the dealer-manager receives a non-itemized bill for due diligence that it has reason to question, then it has the obligation to ensure compliance by requesting an itemized statement to support the bill submitted by the selling agent. If the due diligence bill cannot be justified, any excess over actual due diligence expenses that is paid is considered by the NASD to be undisclosed underwriting compensation and is required to be included within the 10% compensation guideline under NASD Conduct Rule 2810, and reflected on the books and records of the selling agent. However, if the selling agent provides the dealer-manager an itemized bill for actual due diligence expenses which is in excess of .5%, then the excess over .5% will not be included within the 10% compensation guideline, but instead will be included within the 4.5% organization and offering cost guideline under NASD Conduct Rule 2810. 116 The dealer-manager or managing general partner may make certain non-cash compensation arrangements with the selling agents and their registered representatives, which will be included in the accountable reimbursement for permissible non-cash compensation. The dealer-manager is responsible for ensuring that all permissible non-cash compensation arrangements comply with Rule 2810 of the NASD Conduct Rules. For example, payments or reimbursements by the dealer-manager or the managing general partner may be made in connection with meetings held by the dealer-manager or the managing general partner for the purpose of training or education of registered representatives of a selling agent only if the following conditions are met: o the registered representative obtains his selling agent's prior approval to attend the meeting and attendance by the registered representative is not conditioned by his selling agent on the achievement of a sales target; o the location of the training and education meeting is appropriate to the purpose of the meeting as defined in NASD Conduct Rule 2810; o the payment or reimbursement is not applied to the expenses of guests of the registered representative; o the payment or reimbursement by the dealer-manager or the managing general partner is not conditioned by the dealer-manager or the managing general partner on the achievement of a sales target; and o the recordkeeping requirements are met. The dealer-manager will retain any of the accountable reimbursement for permissible non-cash compensation not reallowed to the selling agents. The managing general partner is also using the services of wholesalers who are employed by it or its affiliates and are registered through Anthem Securities. The wholesalers include Mr. Jim O'Mara and three Regional Marketing Directors, Mr. Bruce Bundy, Mr. Robert Gourlay and Ms. Vicki Burbridge. Most of the 2.5% dealer-manager fee will be reallowed to the affiliated wholesalers for subscriptions obtained through their efforts, which includes expense reimbursements to them and a salary to Mr. O'Mara in connection with the offering. The dealer-manager will retain the remainder of the dealer-manager fee not reallowed to the wholesalers, which may be used for such items as legal fees associated with underwriting and salaries of dual employees of the dealer-manager and the managing general partner which are required to be included in underwriting compensation under NASD Conduct Rule 2810 as determined jointly by the managing general partner and the dealer-manager. The offering will be made in compliance with Rule 2810 of the NASD Conduct Rules and all compensation, including non-cash compensation, to broker/dealers and wholesalers, regardless of the source, will be limited to 10% of the gross proceeds of the offering plus the .5% reimbursement for bona fide accountable due diligence expenses 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. Finally, although not anticipated, if the dealer-manager assists in the transfer of units then it will comply with Rule 2810(b)(3)(D) of the NASD Conduct Rules. Subject to the following, you and the other investors will pay $10,000 per unit and generally will share costs, revenues, and distributions in the partnership in which you subscribe in proportion with your respective number of units. However, the subscription price for certain investors will be reduced as set forth below: 117 o the subscription price for the managing general partner, its officers, directors, and affiliates, and investors who buy units through the officers and directors of the managing general partner, will be reduced by an amount equal to the 2.5% dealer-manager fee, the 7% sales commission, the .5% reimbursement for bona fide accountable due diligence expenses, and the .5% accountable reimbursement for permissible non-cash compensation, which will not be paid with respect to these sales; and o the subscription price for registered investment advisors and their clients, and selling agents and their registered representatives and principals, will be reduced by an amount equal to the 7% sales commission, which will not be paid with respect to these sales. No more than 5% of the total units in each partnership may be sold with the discounts described above. These investors who pay a reduced price for their units generally will share in a partnership's costs, revenues, and distributions on the same basis as the other investors who pay $10,000 per unit. Although the managing general partner and its affiliates may buy up to 5% of the units, they do not currently anticipate buying any units. If they do buy units, then those units will not be applied towards the minimum subscription proceeds required for a partnership to begin operations. After the minimum subscriptions are received in a partnership and the checks have cleared the banking system, the dealer-manager fee and the sales commissions will be paid to the dealer-manager and selling agents approximately every two weeks until the offering closes. INDEMNIFICATION The dealer-manager is an underwriter as that term is defined in the 1933 Act and the sales commissions and dealer-manager fees will be deemed underwriting compensation. The managing general partner and the dealer-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 intends to use the following sales material with the offering of the units: o a flyer entitled "Atlas America Public #14-2004 Program"; o an article entitled "Tax Rewards with Oil and Gas Partnerships"; o a brochure of tax scenarios entitled "How an Investment in Atlas America Public #14-2004 Program Can Help Achieve an Investor's Tax Objectives"; o a brochure entitled "Investing in Atlas America Public #14-2004 Program"; o a booklet entitled "Outline of Tax Consequences of Oil and Gas Drilling Programs"; o a brochure entitled "The Appalachian Basin: A Prime Drilling Location Which Commands a Premium"; o a brochure entitled "Investment Insights - Tax Time"; o a brochure entitled "Frequently Asked Questions"; and o possibly other supplementary materials. The managing general partner has not authorized the use of other sales material and the offering of units is made only by means of this prospectus. The sales material is subject to the following considerations: 118 o it must be preceded or accompanied by this prospectus; o it is not complete; o it does not contain any material information which is not also set forth in this prospectus; and o it should not be considered a part of or incorporated into this prospectus or the registration statement of which this prospectus is a part. In addition, supplementary materials, including prepared presentations for group meetings, must be submitted to the state administrators before they are used and their use must either be preceded by or accompanied by a prospectus. Also, all advertisements of, and oral or written invitations to, "seminars" or other group meetings at which the units are to be described, offered, or sold will clearly indicate the following: o that the purpose of the meeting is to offer the units for sale; o the minimum purchase price of the units; o the suitability standards to be employed; and o 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 the registered representatives of the selling agents. You should rely only on the information contained in this prospectus in making your investment decision. No one is authorized to provide you with information that is different. LEGAL OPINIONS Kunzman & Bollinger, Inc., has issued its opinion to the managing general partner regarding the validity and due issuance of the units including assessibility and its opinion on material federal income tax consequences to individual typical investors in the partnerships. However, the factual statements in this prospectus are those of the partnerships or the managing general partner, and counsel has not given any opinions with respect to any of the tax or other legal aspects of this offering except as expressly set forth above. EXPERTS The financial statements included in this prospectus for the managing general partner as of and for the years ended September 30, 2003 and 2002 and the balance sheet for Atlas America Public #14-2004 L.P. as of June 30, 2004, have been audited by Grant Thornton LLP, as of the dates indicated in its reports which appear elsewhere in this prospectus. These financial statements have been included in reliance on its reports given on its authority as experts in auditing and accounting. 119 The geologic evaluations of United Energy Development Consultants, Inc., which is not affiliated with the managing general partner or its affiliates, appearing in this prospectus for the areas where potential prospects have been identified for Atlas America Public #14-2004 L.P. in Appendix A to this prospectus been included in this prospectus on the authority of United Energy Development Consultants, Inc. as an expert with respect to the matters covered by the evaluations and in the giving of the evaluations. LITIGATION The managing general partner knows of no litigation pending or threatened to which the managing general partner or the partnerships are subject or may be a party, which it believes would have a material adverse effect on the partnerships or their business, and no such proceedings are known to be contemplated by governmental authorities or other parties. FINANCIAL INFORMATION CONCERNING THE MANAGING GENERAL PARTNER AND ATLAS AMERICA PUBLIC #14-2004 L.P. Financial information concerning the managing general partner and the first partnership in the program, Atlas America Public #14-2004 L.P., which is the only partnership that has been formed, 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 in which you purchase units. 120 AUDIT REPORT ATLAS AMERICA PUBLIC #14-2004 L.P. (A Delaware Limited Partnership) JUNE 30, 2004 F-1 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Partners Atlas America Public #14-2004 L.P. (A DELAWARE LIMITED PARTNERSHIP) We have audited the accompanying balance sheet of Atlas America Public #14-2004 L.P. (a Delaware Limited Partnership) as of June 30, 2004. This financial statement is the responsibility of the Partnership's management. Our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statement is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement. 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 #14-2004 L.P. as of June 30, 2004, in conformity with accounting principles generally accepted in the United States of America. /s/ GRANT THORNTON LLP Cleveland, Ohio June 30, 2004 F-2 Atlas America Public #14-2004 L.P. (A Delaware Limited Partnership) BALANCE SHEET June 30, 2004 ASSETS $ 100 Cash ================= PARTNERS' CAPITAL $ 100 Partners' capital: ================= The accompanying notes are an integral part of this financial statement. F-3 Atlas America Public #14-2004 L.P. (A Delaware Limited Partnership) NOTES TO FINANCIAL STATEMENT June 30, 2004 1. ORGANIZATION AND DESCRIPTION OF BUSINESS Atlas America Public #14-2004 L.P. (the "Partnership") is a Delaware limited partnership in which Atlas Resources, Inc. ("Atlas Resources") of Pittsburgh, Pennsylvania (a second-tier wholly-owned subsidiary of Atlas America, Inc., a publicly traded company, which is a second-tier 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 Partnerships will be funded to drill development wells which are proposed to be located primarily in the Appalachian Basin located in western Pennsylvania, eastern and southern Ohio and western New York. Subscriptions at a cost of $10,000 per unit, subject to discounts for certain investors, generally will be sold using wholesalers and through broker-dealers including Anthem Securities, Inc., an affiliated company, which will receive, on each unit sold to an investor, a 2.5% dealer-manager fee, a 7% sales commission, a .5% accountable reimbursement for permissible non-cash compensation, and an up to .5% reimbursement of bona fide accountable due diligence expenses. Commencement of Partnership operations is subject to the receipt of minimum Partnership subscriptions of $2,000,000 (up to a maximum of $125,000,000 ) by December 31, 2004. 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS OF ACCOUNTING ------------------- The Partnership will prepare its financial statements in accordance with accounting principles generally accepted in the United States of America. OIL AND GAS PROPERTIES ---------------------- The Partnership will use the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip wells will be capitalized. Depreciation and depletion will be computed on a field-by-field basis by the unit-of-production method based on periodic estimates of oil and gas reserves. Undeveloped leaseholds and proved properties will be assessed periodically or whenever events or circumstances indicate that the carrying amount of these assets may not be recoverable. Proved properties will be assessed based on estimates of future cash flows. F-4 Atlas America Public #14-2004 L.P. (A Delaware Limited Partnership) NOTES TO FINANCIAL STATEMENT - CONTINUED June 30, 2004 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) USE OF ESTIMATES ---------------- The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. 3. FEDERAL INCOME TAXES The Partnership will not be treated as a taxable entity for federal income tax purposes. Any item of income, gain, loss, deduction or credit would flow through to the partners as though each partner has incurred such item directly. As a result, each partner must take into account their pro rata share under the partnership agreement of all items of partnership income and deductions in computing their federal income tax liability. 4. PARTICIPATION IN REVENUES AND COSTS The Managing General Partner and the investor partners will participate in revenues and costs in the following manner:
MANAGING GENERAL INVESTOR PARTNER PARTNERS -------- -------- PARTNERSHIP COSTS Organization and offering costs............................................100% 0% Lease costs................................................................100% 0% Intangible drilling costs....................................................0% 100% Equipment costs (1).........................................................66% 34% Operating costs, administrative costs, direct costs, and all other costs.................................................................(2) (2) PARTNERSHIP REVENUES Interest income.............................................................(3) (3) Equipment proceeds (1)......................................................66% 34% All other revenues including production revenues.........................(4)(5) (4)(5)
--------------------- (1) These percentages may vary. If the total equipment costs for all of the partnership's wells that would be charged to the investor partners exceeds an amount equal to 10% of the subscription proceeds of investor partners in the partnership, then the excess will be charged to the managing general partner. Equipment proceeds, if any, will be credited in the same percentage in which the equipment costs were charged. F-5 Atlas America Public #14-2004 L.P. (A Delaware Limited Partnership) NOTES TO FINANCIAL STATEMENT - CONTINUED June 30, 2004 4. PARTICIPATION IN REVENUES AND COSTS -CONTINUED (2) These costs will be charged to the parties in the same ratio as the related production revenues are being credited. These costs also include plugging and abandonment costs of the wells after the wells have been drilled and produced. (3) Interest earned on subscription proceeds before the final closing of the partnership will be credited to their account and paid not later than the partnership's first cash distributions from operations. After the final closing of the partnership and until the subscription proceeds are invested in the partnership's natural gas and oil operations any interest income from temporary investments will be allocated pro rata to the investor partners providing the subscription proceeds. All other interest income, including interest earned on the deposit of operating revenues, will be credited as natural gas and oil production revenues are credited. (4) The managing general partner and the investor partners in the partnership will share in all of the partnership's other revenues in the same percentage as their respective capital contributions bears to the total partnership capital contributions except that the managing general partner will receive an additional 7% of the partnership revenues. However, the managing general partner's total revenue share may not exceed 35% of partnership revenues. (5) The actual allocation of partnership revenues between the managing general partner and the investor partners will vary from the allocation described in (4) above if a portion of the managing general partner's partnership net production revenues is subordinated as described in note 7. 5. TRANSACTIONS WITH ATLAS RESOURCES AND ITS AFFILIATES The Partnership intends to enter into the following significant transactions with Atlas Resources and its affiliates as provided under the Partnership agreement: The partnership will enter into a drilling and operating agreement with Atlas Resources to drill and complete all of the Partnership wells at cost plus 15%. The cost of the wells includes reimbursement to Atlas Resources of the investor partners' share of its general and administrative overhead cost (approximately $12,722 per well, which will be proportionately reduced if the Partnership's working interest in a well is less than 100 %) and all ordinary and actual costs of drilling, testing and completing the wells. Atlas Resources will receive an unaccountable, fixed payment reimbursement for their administrative costs at $75 per well per month, which will be proportionately reduced if the partnership's working interest in a well is less than 100%. Atlas Resources will receive well supervision fees for operating and maintaining the wells during producing operations at a competitive rate (currently the competitive rate is $285 per well per month in the primary and secondary drilling areas). The well supervision fees will be proportionately reduced if the partnership's working interest in a well is less than 100%. F-6 Atlas America Public #14-2004 L.P. (A Delaware Limited Partnership) NOTES TO FINANCIAL STATEMENT - CONTINUED June 30, 2004 5. TRANSACTIONS WITH ATLAS RESOURCES AND ITS AFFILIATES - CONT. Atlas Resources will charge the partnership a fee for gathering and transportation at a competitive rate (currently in the range of $.29 to $.70 per MCF in the primary and secondary drilling areas). Atlas Resources will contribute all the undeveloped leases necessary to cover each of the partnership's prospects and will receive a credit for its capital account in the partnership equal to the cost of the leases (approximately $5,232 per prospect which will be proportionately reduced if the Partnership's working interest is the prospect is less than 100%). As the Managing General Partner, Atlas Resources will perform all administrative and management functions for the partnership including billing and collecting revenues and paying expenses. Atlas Resources will be reimbursed for all direct costs expended on behalf of the partnership. 6. PURCHASE COMMITMENT Subject to certain conditions, investor partners may present their interests beginning with the fifth calendar year after the partnership closes for purchase by the Managing General Partner. The Managing General Partner is not obligated to purchase more than 5% of the units in any calendar year. In the event that the Managing General Partner is unable to obtain the necessary funds, the Managing General Partner may suspend its purchase obligation. 7. SUBORDINATION OF PORTION OF MANAGING GENERAL PARTNER'S NET REVENUE SHARE The Managing General Partner will subordinate up to 50% of its share of production revenues of the Partnership, net of related operating costs, direct costs, administrative costs and all other costs not specifically allocated to the receipt by the other partners of cash distributions from the Partnership equal to at least 10% per unit, based on $10,000 per unit regardless of the actual price paid, determined on a cumulative basis, in each of the first five 12-month periods beginning with Partnership's first cash distributions from operations. 8. INDEMNIFICATION In order to limit the potential liability of the investor general partners, Atlas Resources has agreed to indemnify each investor general partner from any liability incurred which exceeds such partner's share of Partnership net assets and insurance proceeds. F-7 REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS Board of Directors ATLAS RESOURCES, INC. We have audited the accompanying consolidated balance sheets of ATLAS RESOURCES, INC. (a Pennsylvania corporation) and subsidiary as of September 30, 2003 and 2002, and the related consolidated statements of income, comprehensive income, changes in stockholder's equity, and cash flows for the years then ended. 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 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 audits provide a reasonable basis for our opinion. In our opinion, the 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, 2003 and 2002, and the consolidated results of their operations and cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 2 to the consolidated financial statements, effective October 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, and changed its method of accounting for its plugging and abandonment liability related to its oil and gas wells and associated pipelines and equipment. As discussed in Note 3 to the consolidated financial statements, effective October 1, 2001, the Company changed its method of accounting for goodwill for the adoption of Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets. /s/ Grant Thornton LLP Cleveland, Ohio December 5, 2003 F-8 ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS SEPTEMBER 30, 2003 AND 2002
2003 2002 ----------- -------- (in thousands, except share data) ASSETS Current assets: Cash and cash equivalents........................................................... $ 4,702 $ 698 Accounts receivable ................................................................ 4,895 5,419 Prepaid expenses.................................................................... 532 320 ---------- ---------- Total current assets.............................................................. 10,129 6,437 Property and equipment: Oil and gas properties and equipment (successful efforts).......................... 85,199 59,757 Buildings and land................................................................. 2,830 2,830 Other.............................................................................. 414 394 ---------- ---------- 88,443 62,981 Less - accumulated depreciation, depletion, and amortization........................... (16,388) (10,995) ----------- ----------- Net property and equipment......................................................... 72,055 51,986 Goodwill............................................................................... 20,868 20,868 Intangible assets...................................................................... 3,922 4,400 ----------- ------------ $ 106,974 $ 83,691 ========== =========== LIABILITIES AND STOCKHOLDER'S EQUITY Current liabilities: Current portion of long-term debt................................................... $ 56 $ - Accounts payable.................................................................... 6,223 3,272 Liabilities associated with drilling contracts...................................... 22,157 4,948 Accrued liabilities................................................................. 875 108 Advances and note from parent....................................................... 51,150 51,054 ---------- ---------- Total current liabilities...................................................... 80,461 59,382 Asset retirement obligation............................................................ 701 - Long-term debt 138 - Commitments and contingencies.......................................................... - - Stockholder's equity: Common stock, stated at $10 per share; 500 authorized shares; 200 shares issued and outstanding.......................... 2 2 Additional paid-in capital.......................................................... 16,505 16,505 Accumulated other comprehensive income (loss)....................................... - (212) Retained earnings................................................................... 9,167 8,014 ---------- ---------- Total stockholder's equity........................................................ 25,674 24,309 ---------- ---------- $ 106,974 $ 83,691 ========== ==========
See accompanying notes to consolidated financial statements F-9 ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED STATEMENTS OF INCOME YEARS ENDED SEPTEMBER 30, 2003 AND 2002
2003 2002 ----------- -------- (in thousands) REVENUES Well Drilling................................................................ $ 52,879 $ 49,516 Gas and Oil Production....................................................... 16,091 10,056 Well Services................................................................ 6,014 5,758 Other........................................................................ 130 154 ---------- ---------- 75,114 65,484 COSTS AND EXPENSES Well Drilling................................................................ 45,982 42,996 Gas and oil production and exploration....................................... 2,312 2,178 Well Services................................................................ 923 1,108 Non-direct................................................................... 15,985 11,122 Depreciation, depletion and amortization..................................... 6,229 4,595 Interest..................................................................... 2,375 2,522 ---------- ---------- 73,806 64,521 ---------- ---------- Income from operations before income taxes................................... 1,308 963 Provision for income taxes................................................... 275 135 ---------- ---------- Income before cumulative effect of accounting change......................... 1,033 828 Cumulative effect of change in accounting principle, net of income taxes of $65 120 -- ---------- ---------- Net income................................................................... $ 1,153 $ 828 ========= ==========
See accompanying notes to consolidated financial statements F-10
ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME YEARS ENDED SEPTEMBER 30, 2003 AND 2002 2003 2002 ---------- ---------- (in thousands) Net income................................................................................... $ 1,153 $ 828 Other comprehensive income (loss): Unrealized holding losses on natural gas futures arising during the period, net of taxes of (541) (264) $245 and $118........................................................................... Less: reclassification adjustment for losses realized in net income, net of taxes of $355 and $17............................................................................ 753 42 ---------- ---------- 212 (222) ---------- ----------- Comprehensive income.......................................................................... $ 1,365 $ 606 ========== ==========
See accompanying notes to consolidated financial statements F-11
ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY YEARS ENDED SEPTEMBER 30, 2003 AND 2002 (in thousands, except share data) Accumulated Common Stock Additional Other Totals ---------------------- Paid-In Comprehensive Retained Stockholder's Shares Amount Capital Income (Loss) Earnings Equity - ------------------------------------------------------------------------------------------------------------------------------------ Balance, September 30, 2001.................. 200 $ 2 $ 16,505 $ 10 $ 7,186 $ 23,703 Net unrealized loss.......................... - - - (222) - (222) Net income................................... - - - - 828 828 - ------------------------------------------------------------------------------------------------------------------------------------ Balance, September 30, 2002.................. 200 $ 2 $ 16,505 $ (212) $ 8,014 $ 24,309 Net unrealized gain.......................... - - - 212 - 212 Net income................................... - - - - 1,153 1,153 - ------------------------------------------------------------------------------------------------------------------------------------ Balance, September 30, 2003.................. 200 $ 2 $ 16,505 $ - $ 9,167 $ 25,674 ======= ====== ============= ========= ========= ===========
See accompanying notes to consolidated financial statements F-12 ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS YEARS ENDED SEPTEMBER 30, 2003 AND 2002
2003 2002 ----------- ---------- (in thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income................................................................. $ 1,153 $ 828 Adjustments to reconcile net income to net cash provided by operating activities: Cumulative effect of change in accounting principle..................... (120) - Depreciation, depletion and amortization................................ 6,229 4,595 Management fees and interest on intercompany note due to parent......... 15,074 12,399 Gain on sale of assets.................................................. (19) - Changes in operating assets and liabilities: Increase in accounts receivable and other current assets............... (161) (234) Increase (decrease) in accounts payable and other liabilities.......... 17,798 (13,716) ------ -------- Net cash provided by operating activities.................................. 39,954 3,872 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures....................................................... (21,106) (14,757) Proceeds from sale of assets............................................... 19 - ---------- ---------- Net cash used in investing activities...................................... (21,087) (14,757) CASH FLOWS FROM FINANCING ACTIVITIES: Principal payments on borrowings........................................... (34) - Net (payments to) advances from Parent..................................... (14,829) 6,225 ----------- ---------- Net cash (used in) provided by financing activities........................ (14,863) 6,225 ----------- ---------- Increase (decrease) in cash and cash equivalents........................... 4,004 (4,660) Cash and cash equivalents at beginning of year............................. 698 5,358 ---------- ---------- Cash and cash equivalents at end of year................................... $ 4,702 $ 698 ========== ==========
See accompanying notes to consolidated financial statements F-13 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1 - NATURE OF OPERATIONS Atlas Resources, Inc. (the "Company"), a Pennsylvania corporation, 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. The Company is a second-tier wholly-owned subsidiary of Atlas America, Inc. (Atlas). Atlas is a second-tier wholly-owned subsidiary of Resource America, Inc. (RAI), a publicly traded company (trading under the symbol REXI on the NASDAQ System) operating in the energy, real estate, and financial services sectors. The Company's operations are dependent upon the resources and services provided by Atlas. . The Company finances a substantial portion of its drilling activities through drilling partnerships it sponsors and typically acts as the managing general partner of these partnerships and has a material partnership interest. NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES RECLASSIFICATIONS Certain reclassifications have been made to the fiscal 2002 consolidated financial statements to conform to the fiscal 2003 presentation. PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of the Company and its wholly owned subsidiary. The Company also owns individual interests in the assets, and is separately liable for its share of the liabilities of energy partnerships, whose activities include only exploration and production activities. In accordance with established practice in the oil and gas industry, the Company includes its pro-rata share of assets, liabilities, income and costs and expenses of the energy partnerships in which the Company has an interest. All material intercompany transactions have been eliminated. USE OF ESTIMATES Preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and costs and expenses during the reporting period. Actual results could differ from these estimates. 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. F-14 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED) COMPREHENSIVE INCOME Comprehensive income (loss) includes net income and all other changes in the equity of a business during a period from transactions and other events and circumstances from non-owner sources. These changes, other than net income, are referred to as "other comprehensive income" and for the Company only include changes in the fair value, net of taxes, of unrealized hedging gains and losses. PROPERTY AND EQUIPMENT Property and equipment consists of the following:
At September 30, ---------------------------- 2003 2002 ----------- ------------- (in thousands) Mineral interest in properties: Proved properties........................................................ $ 1 $ 1 Unproved properties...................................................... 25 22 Wells and related equipment.................................................. 84,435 59,484 Support equipment............................................................ 738 250 Other........................................................................ 3,244 3,224 ----------- ------------ 88,443 62,981 Accumulated depreciation, depletion, amortization and valuation allowances: Oil and gas properties................................................... (15,834) (10,506) Other (554) (489) ------------ ------------- (16,388) (10,995) ------------ ------------- $ 72,055 $ 51,896 =========== ============
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 or, if this determination cannot be made, within twelve months of completion of drilling. 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 as incurred. Production costs, overhead and all exploration costs other than the costs of exploratory drilling are charged to expense as incurred. Oil and gas properties at September 30, 2003, include mineral rights with a cost of $26,000 before accumulated depletion. In connection with a review of RAI's financial statements by the staff of the Securities and Exchange Commission, the Company has been made aware that an issue has arisen within the industry regarding the application of provisions of Statement of Financial Accounting Standards ("SFAS") No. 142, "Goodwill and Other Intangible Assets" and SFAS No. 141, "Business Combinations," to companies in the extractive industries, including gas and oil companies. The issue is whether SFAS No. 142 requires companies to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the balance sheet, apart from other capitalized gas and oil property costs. Historically, the Company and other gas and oil companies have included the cost of these gas and oil leasehold interests as part of gas and oil properties. Also under consideration is whether SFAS No. 142 requires companies to provide the additional disclosures prescribed by SFAS No. 142 for intangible assets for costs associated with mineral rights. F-15 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED) OIL AND GAS PROPERTIES - (CONTINUED) If it is ultimately determined that SFAS No. 142 requires the Company to reclassify costs associated with mineral rights from property and equipment to intangible assets, the amounts would be immaterial to the Company's financial position. The reclassification of these amounts would not affect the method in which such costs are amortized or the manner in which the Company assesses impairment of capitalized costs. As a result, net income would not be affected by the reclassification. The Company assesses unproved and proved properties periodically to determine whether there has been a decline in value and, if a decline is indicated, a loss is recognized. The assessment of significant unproved properties for impairment is on a property-by-property basis. The Company considers whether a dry hole has been drilled on a portion of, or in close proximity to the property, the Company's intentions of further drilling, the remaining lease term of the property, and its experience in similar fields in close proximity. The Company assesses unproved properties whose costs are individually insignificant in the aggregate. This assessment includes considering the Company's experience with similar situations, the primary lease terms, the average holding period of unproved properties and the relative proportion of such properties on which proved reserves have been found in the past. The Company compares the carrying value of its proved developed gas and oil producing properties to the estimated future cash flow from such properties in order to determine whether their carrying values should be reduced. No adjustment was necessary during any of the fiscal years in the two year period ended September 30, 2003. Upon the sale or retirement of a complete or partial unit of a proved property, the cost and related accumulated depletion are eliminated from the property accounts, and the resultant gain or loss is recognized in the statement of operations. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the statement of operations. If a partial interest in an unproved property is sold, any funds received are accounted for as a reduction of the cost in the interest retained. 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 estimates the salvage value of equipment recoverable upon abandonment. At September 30, 2002, the Company's estimate of equipment salvage values was greater than or equal to the estimated costs of future dismantlement, restoration, reclamation, and abandonment. On October 1, 2002, the Company adopted SFAS No. 143 "Accounting for Asset Retirement Obligations" ("SFAS 143") as discussed further in this footnote. DEPRECIATION, DEPLETION AND AMORTIZATION The Company amortizes proved gas and oil properties, which include intangible drilling and development costs, tangible well equipment and leasehold costs, on the unit-of-production method using the ratio of current production to the estimated aggregate proved developed gas and oil reserves. The Company computes depreciation on property and equipment, other than gas and oil properties, using the straight-line method over the estimated economic lives, which range from three to 39 years. F-16 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED) ASSET RETIREMENT OBLIGATIONS Effective October 1, 2002, the Company adopted SFAS 143 which requires the Company to recognize an estimated liability for the plugging and abandonment of its oil and gas wells and associated pipelines and equipment. Under SFAS 143, the Company must currently recognize a liability for future asset retirement obligations if a reasonable estimate of the fair value of that liability can be made. The present values of the expected asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. SFAS 143 requires the Company to consider estimated salvage value in the calculation of depletion, depreciation and amortization. Consistent with industry practice, historically the Company had determined the cost of plugging and abandonment on its oil and gas properties would be offset by salvage values received. The adoption of SFAS 143 resulted in (i) an increase of total liabilities because retirement obligations are required to be recognized, (ii) an increase in the recognized cost of assets because the retirement costs are added to the carrying amount of the long-lived assets and (iii) a decrease in depletion expense, because the estimated salvage values are now considered in the depletion calculation. The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserves estimates, external estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The adoption of SFAS 143 as of October 1, 2002 resulted in a cumulative effect adjustment to record (i) a $558,000 increase in the carrying values of proved properties, (ii) a $308,000 decrease in accumulated depletion and (iii) a $681,000 increase in non-current plugging and abandonment liabilities. The pro forma effect of the application of SFAS 143 was not material to the Company's consolidated statements of operations. The Company has no assets legally restricted for purposes of settling asset retirement obligations. Except for the item previously referenced, the Company has determined that there are no other material retirement obligations associated with tangible long-lived assets. A reconciliation of the Company's liability for well plugging and abandonment costs for the year ended September 30, 2003 is as follows (in thousands): Asset retirement obligations, September 30, 2002............. $ - Adoption of SFAS 143......................................... 681 Liabilities incurred......................................... 93 Liabilities settled.......................................... (53) Revision in estimates........................................ (66) Accretion expense............................................ 46 --------- Asset retirement obligations, September 30, 2003............. $ 701 ======== The above accretion expense is included in depreciation, depletion and amortization in the Company's consolidated statements of income and the asset retirement obligation liabilities are classified as long-term liabilities in the Company's consolidated balance sheet. F-17 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED) FAIR VALUE OF FINANCIAL INSTRUMENTS The Company used the following methods and assumptions in estimating the fair value of each class of financial instruments for which it is practicable to estimate fair value. For cash and cash equivalents, receivables and payables, the carrying amounts approximate fair value because of the short maturity of these instruments. For long-term debt, the carrying value approximates fair value because interest rates approximate current market rates. CONCENTRATION OF CREDIT RISK Financial instruments, which potentially subject the Company to concentrations of credit risk, consist principally of periodic temporary investments of cash. The Company places its temporary cash investments in high-quality short-term money market instruments and deposits with high-quality financial institutions and brokerage firms. At September 30, 2003, the Company had $4.7 million in deposits at various banks, of which $4.5 million is over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments. ENVIRONMENTAL MATTERS The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. The Company accounts for environmental contingencies in accordance with SFAS No. 5 "Accounting for Contingencies." Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. The Company maintains insurance that may cover in whole or in part certain environmental expenditures. For the two years ended September 30, 2003, the Company had no environmental matters requiring specific disclosure or requiring recording of a liability. REVENUE RECOGNITION The Company conducts certain energy activities through, and a portion of its revenues are attributable to, sponsored energy limited partnerships. These energy partnerships raise capital from investors to drill gas and oil wells. The Company serves as general partner of the energy partnerships and assumes customary rights and obligations for them. 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 income from the Company's general partner interest is recorded when the gas and oil are sold by a partnership. F-18 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED) REVENUE RECOGNITION - (CONTINUED) The Company contracts with the energy partnerships to drill partnership wells. The contracts require that the energy partnerships must pay the Company the full contract price upon execution. The income from a drilling contract is recognized as the services are performed. The contracts are typically completed in less than 60 days. The Company classifies the difference between the contract payments it has received and the revenue earned as a current liability, included in liabilities associated with drilling contracts. The Company recognizes transportation revenues at the time the natural gas is delivered to the purchaser and includes them in well services revenues. The Company recognizes field services revenues at the time the services are performed. The Company is entitled to receive management fees according to the respective partnership agreements. The Company recognizes such fees as income when earned and includes them in well services revenues. The Company sells interests in gas and oil wells and retains a working interest and/or overriding royalty. The Company records the income from the working interests and overriding royalties when the gas and oil are sold. SUPPLEMENTAL CASH FLOW INFORMATION The Company considers temporary investments with maturity at the date of acquisition of 90 days or less to be cash equivalents. Supplemental disclosure of cash flow information:
Years Ended September 30, -------------------------- 2003 2002 ----------- -------- (in thousands) CASH PAID DURING THE YEARS FOR: Interest..................................................................... $ 110 $ 114 Income taxes paid............................................................ $ 363 $ - NON-CASH ACTIVITIES INCLUDE THE FOLLOWING: Fixed asset purchases financed with long-term debt $ 228 $ - Asset Retirement Obligation.................................................. $ 754 $ -
INCOME TAXES The Company is included in the consolidated federal income tax return of RAI. Income taxes are presented as if the Company had filed a return on a separate company basis utilizing their calculated effective rate of 21% and 14% for fiscal years 2003 and 2002 respectively. The Company's effective tax rate is lower than the federal statutory rate due to the benefit of percentage depletion and fuel credits. Deferred taxes, which are included in Advances from Parent, reflect the tax effect of 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. F-19 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (CONTINUED) RECENTLY ISSUED FINANCIAL ACCOUNTING STANDARDS In July 2002, SFAS No. 146, ("SFAS 146") "Accounting for Costs Associated with Exit or Disposal Activities" was issued. SFAS 146 is effective for exit or disposal activities initiated after December 31, 2002. The adoption of SFAS 146 did not have a material effect on the Company's financial position or results of operations. In May 2003, the FASB issued SFAS No. 150 ("SFAS 150") "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." SFAS 150 requires that certain instruments that were previously classified as equity on a Company's statement of financial position now be classified as liabilities. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The adoption of SFAS 150 did not have a material impact on the Company's results of operations or financial position. In April 2003, the FASB issued SFAS No. 149 ("SFAS 149") "Amendment of Statement 133 on Derivative Instruments and Hedging Activates." SFAS 149 is effective for contracts entered into or modified after June 30, 2003 and amends and clarifies financial accounting and reporting for derivative instruments. The adoption of SFAS 149 did not have a material effect on the Company's financial position or results of operations. In November 2002, the FASB issued Interpretation 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" ("FIN 45"). FIN 45 clarifies the requirements of FASB No. 5, "Accounting for Contingencies" ("SFAS 5") relating to a guarantor's accounting for, and disclosure of, the issuance of certain types of guarantees. FIN 45 provides for additional disclosure requirements related to guarantees in financial statements for financial periods ending after December 15, 2002. Additionally, FIN 45 outlines provisions for initial recognition and measurement of the liability incurred upon the issuance of new guarantees or the modification of existing guarantees subsequent to December 31, 2002. The adoption of the recognition and measurement requirements of FIN 45 on January 1, 2003, did not have a significant impact on the results of operations or financial position of the Company. In January 2003, the Financial Accounting Standards Board issued FASB Interpretation No. 46 "Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51" ("FIN 46"). FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective for all new variable interest entities created or acquired after January 31, 2003. The provisions of FIN 46 must be applied for the first interim or annual period beginning after June 15, 2003. The Company does not have any entities that require disclosure or new consolidation as a result of adopting the provisions of FIN 46. NOTE 3 - INTANGIBLE ASSETS AND GOODWILL INTANGIBLE ASSETS Intangible assets consist of partnership management and operating contracts acquired through acquisitions and recorded at fair value on their acquisition dates. The Company amortizes contracts acquired on a declining balance method, over their respective estimated lives, ranging from five to thirteen years. Amortization expense for the years ended September 30, 2003 and 2002 was $478,000 and $414,000, respectively. The estimated amortization expense for the next five fiscal years is $478,000 F-20 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 3 - OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL - (CONTINUED) The following table provides information about intangible assets at the dates indicated:
At September 30, ------------------------ 2003 2002 ---------- ---------- (in thousands) Partnership management and operating contracts............................ $ 6,353 $ 6,353 Accumulated amortization.................................................. (2,431) (1,953) ---------- ---------- Intangible assets, net.................................................... $ 3,922 $ 4,400 ========== ==========
GOODWILL On October 1, 2001, the Company early-adopted SFAS No. 142 ("SFAS 142") "Goodwill and Other Intangible Assets," which requires that goodwill no longer be amortized, but instead tested for impairment at least annually. At that time, the Company had unamortized goodwill of $14.4 million. The transitional impairment test required upon adoption of SFAS 142, which involved the use of estimates related to the fair market value of the business operations associated with the goodwill, did not indicate an impairment loss. The Company will continue to evaluate its goodwill at least annually and will reflect the impairment of goodwill, if any, in operating income in the statement of operations in the period in which the impairment is indicated. Changes in the carrying amount of goodwill for the periods indicated are as follows:
Years Ended September 30, ------------------------- 2003 2002 ----------- ------- (in thousands) Goodwill at beginning of period (less accumulated amortization of $2,320 and $1,609)..................... $ 20,868 $ 14,479 Syndication network reclassified from other assets in accordance with SFAS 142 (net of accumulated amortization of $711)................................................................. - 6,389 ----------- ---------- Goodwill at end of period (net of accumulated amortization of $2,320 and $2,320).................................................... $ 20,868 $ 20,868 =========== ==========
NOTE 4 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS The Company conducts certain energy activities through, and a substantial portion of its revenues are attributable to energy limited partnerships ("Partnerships"). The Company serves as general partner of the Partnerships and assumes customary rights and obligations for the Partnerships. As the general partner, the Company is liable for Partnership liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Partnerships. The Company is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Partnerships' revenue and costs and expenses according to the respective Partnership agreements. F-21 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 4 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS - (CONTINUED) The advances from Parent represent amounts owed for advances and transactions in the normal course of business and a note payable to the parent. Other than the note, these advances have no repayment terms and are subordinated to any third-party debt. The note, which is also subordinated to any third-party debt, has a face amount of $15.0 million and accrues interest at an annual rate of 9.50% on any unpaid balances. The principal and any unpaid interest are due upon demand by the Parent. Interest expense related to the note, which is being deferred, was $1.9 million for each of the years ended September 30, 2003 and 2002. The advances have no repayment terms and the note is due on demand. Therefore the Company has classified the amounts due the Parent as a current liability on its Consolidated Balance Sheets. The Parent does not intend to demand payment on the advances or note within the next year. The Company is dependent on its' Parent for management and administrative functions and financing for capital expenditures. The Company pays a management fee to its Parent for management and administrative services, which amounted to $13.1 million and $10.5 million for the years ended September 30, 2003 and 2002, respectively. NOTE 5 - DEBT
At September 30, ------------------------- 2003 2002 ---------- ---------- (in thousands) Long-term debt....................................................... $ 194 $ - --------- --------- 194 - Less current maturities.............................................. 56 - ---------- ---------- $ 138 $ - ========== ==========
Annual debt principal payments over the next five fiscal years ending September 30 are as follows: (in thousands): 2004............................... $ 56 2005............................... $ 56 2006............................... $ 56 2007............................... $ 26 2008............................... $ -
During the current fiscal year ended September 30, 2003, the Company entered into two loans through General Motors Acceptance Corporation to finance the purchase of ten trucks used in its' well drilling and oil and gas production activities. The first loan has a principal amount of $115,378 and bears an annual interest rate of 2.9%. The second loan has a principal amount of $113,046 and bears an annual interest rate of 1.9%. Both loans have a 48 month repayment term. F-22 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 6 - COMMITMENTS AND CONTINGENCIES The Company leases office space and equipment under leases with varying expiration dates through 2006. Rental expense was $359,000 and $376,000 for the years ended September 30, 2003 and 2002, respectively. At September 30, 2003, future minimum rental commitments for the next five fiscal years were as follows (in thousands): 2004............................ $ 213 2005............................ 168 2006............................ 17 2007............................ - 2008............................ - The Company is the managing general partner of various energy partnerships, and has agreed to indemnify each investor partner from any liability that exceeds such partner's share of partnership assets. Subject to certain conditions, investor partners in certain energy partnerships have the right to present their interests for purchase by the Company, as managing general partner. The Company is not obligated to purchase more than 5% or 10% of the units in any calendar year. Based on past experience, the Company believes that any liability incurred would not be material. The Company may be required to subordinate a part of its net partnership revenues to the receipt by investor partners of cash distributions from the energy partnerships equal to at least 10% of their agreed subscriptions determined on a cumulative basis, in accordance with the terms of the partnership agreements. The Company has access to a revolving credit facility from its parent. In July 2002, the Company's parent entered into a $75.0 million credit facility led by Wachovia Bank. The revolving credit facility has a current borrowing base of $54.2 million which may be increased or decreased subject to growth in the Parent's oil and gas reserves, including those of the Company. The facility permits draws based on the remaining proved developed non-producing and proved undeveloped natural gas and oil reserves attributable to the Parent's wells and the projected fees and revenues from operation of the wells and the administration of energy partnerships. Up to $10.0 million of the facility may be in the form of standby letters of credit. The facility is secured by the Parent's assets, including those of the Company. The revolving credit facility has a term ending in July 2005 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) Wachovia prime rate plus between 25 to 75 basis points, or (ii) LIBOR plus between 175 and 225 basis points. The facility terminates in July 2005, when all outstanding borrowings must be repaid. At September 30, 2003 and 2002, $32.3 million and $45.0 million, respectively, were outstanding under this facility, including $1.3 million each year under letters of credit. The interest rates ranged from 2.88% to 2.90% at September 30, 2003. The Company owed no amounts due under this facility at September 30, 2003 and 2002. The Company is a party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Company's financial position or results of operations. F-23 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 7 - HEDGING ACTIVITIES The Company from time to time enters into natural gas futures and option contracts to hedge its exposure to changes in natural gas prices. At any point in time, such contracts may include regulated New York Mercantile Exchange ("NYMEX") futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. The Company formally documents all relationships between hedging instruments and the items being hedged, including the Company's risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. The Company assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives are highly effective in offsetting changes in the fair value of hedged items. Historically these contracts have qualified and been designated as cash flow hedges and recorded at their fair values. Gains or losses on future contracts are determined as the difference between the contract price and a reference price, generally prices on NYMEX. Such gains and losses are charged or credited to accumulated other comprehensive income (loss) and recognized as a component of sales revenue in the month the hedged gas is sold. If it is determined that a derivative is not highly effective as a hedge or it has ceased to be a highly effective hedge, due to the loss of correlation between changes in gas reference prices under a hedging instrument and actual gas prices, the Company will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings. At September 30, 2003, the Company had no open natural gas futures contracts related to natural gas sales and accordingly, had no unrealized loss or gain related to open NYMEX contracts at that date. Its net unrealized loss was approximately $316,600 at September 30, 2002. The Company recognized a loss of $1.1 million and $59,000 on settled contracts covering natural gas production for the years ended September 30, 2003 and 2002, respectively. The Company recognized no gains or losses during the two year period ended September 30, 2003 for hedge ineffectiveness or as a result of the discontinuance of cash flow hedges. Although hedging provides the Company some protection against falling prices, these activities could also reduce the potential benefits of price increases, depending upon the instrument. NOTE 8 - MAJOR CUSTOMERS The Company's natural gas is sold under contract to various purchasers. For the years ended September 30, 2003 and 2002, gas sales to First Energy Solutions Corporation accounted for 15% and 17%, respectively, of total revenues. F-24 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION Results of operations from oil and gas producing activities:
Years Ended September 30, -------------------------- 2003 2002 ---------- -------- (in thousands) Revenues..................................................................... $ 16,091 $ 10,056 Production costs............................................................. (1,992) (1,543) Exploration expenses......................................................... (320) (635) Depreciation, depletion and amortization..................................... (5,605) (3,949) Income taxes................................................................. (2,609) (1,075) ---------- ---------- Results of operations from oil and gas producing activities.................. $ 5,565 $ 2,854 ========== ==========
Capitalized Costs Related to Oil and Gas Producing Activities. The components of capitalized costs related to the Company's oil and gas producing activities are as follows:
At September 30, ----------------------- 2003 2002 ---------- -------- (in thousands) Proved properties............................................................ $ 1 $ 1 Unproved properties.......................................................... 25 22 Wells and related equipment and facilities................................... 84,435 59,484 Support equipment and facilities............................................. 738 250 ----------- ----------- 85,199 59,757 Accumulated depreciation, depletion, amortization and valuation allowances....................................................... (15,834) (10,506) ----------- ----------- Net capitalized costs................................................... $ 69,365 $ 49,251 =========== ===========
Costs Incurred in Oil and Gas Producing Activities. The costs incurred by the Company in its oil and gas activities during fiscal years 2003 and 2002 are as follows:
Years Ended September 30, ------------------------- 2003 2002 ---------- -------- (in thousands) Property acquisition costs: Unproved properties........................................................ $ - $ 4 Proved properties.......................................................... $ - $ 1 Exploration costs............................................................ $ 320 $ 635 Development costs............................................................ $ 24,588 $ 19,018
The development costs above for the years ended September 30, 2003 and 2002 were substantially all incurred for the development of proved undeveloped properties. F-25 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION - (CONTINUED) Oil and Gas Reserve Information (Unaudited). The estimates of the Company's proved and unproved gas reserves are based upon evaluations made by management and verified by Wright & Company, Inc., an independent petroleum engineering firm, as of September 30, 2003 and 2002. All reserves are located within the United States. Reserves are estimated in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board which require that reserve estimates be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and 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. o Reservoirs are considered proved if economic feasibility is supported by either actual production or conclusive formation tests. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. o 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. o Estimates of proved reserves do not include the following: (a) oil that may become available from known reservoirs but is classified separately as "indicated additional reservoirs"; (b) crude oil, natural gas, and 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 and natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operation methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measures of discounted future net cash flows may not represent the fair market value of the Company's oil and gas reserves or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors for effects have not been proved. F-26 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION - (CONTINUED) The Company's reconciliation of changes in proved reserve quantities is as follows (unaudited):
Gas Oil (Mcf) (Bbls) ----------- --------- Balance September 30, 2001............................................ 71,943,564 82,532 Current additions................................................ 17,855,966 43,089 Transfers to limited partnerships................................ (7,396,491) (65,692) Revisions........................................................ (5,321,048) (1,876) Production....................................................... (2,944,605) (3,505) ---------- ------- Balance September 30, 2002............................................ 74,137,386 54,548 Current additions................................................ 21,663,845 29,394 Transfers to limited partnerships................................ (8,688,298) (31,386) Revisions........................................................ 44,613 16,631 Production....................................................... (3,327,168) (6,772) ----------- ------- Balance September 30, 2003............................................ 83,830,378 62,415 ========== ====== Proved developed reserves at: September 30, 2003............................................... 39,021,728 33,021 September 30, 2002............................................... 36,250,709 23,162
The following schedule presents the standardized measure of estimated discounted future net cash flows relating to proved oil and gas reserves. The estimated future production is priced at fiscal year-end prices, adjusted only for fixed and determinable increases in natural gas and oil prices provided by contractual agreements. The resulting estimated future cash inflows are reduced by estimated future costs to develop and produce the proved reserves based on fiscal year-end cost levels. The future net cash flows are reduced to present value amounts by applying a 10% discount factor. The standardized measure of future cash flows was prepared using the prevailing economic conditions existing at September 30, 2003 and 2002 and such conditions continually change. Accordingly such information should not serve as a basis in making any judgment on the potential value of recoverable reserves or in estimating future results of operations (unaudited).
Years Ended September 30, 2003 2002 ----------- ----------- (in thousands) Future cash inflows..................................................... $ 411,317 $ 288,574 Future production costs................................................. (82,517) (63,697) Future development costs................................................ (71,299) (54,060) Future income tax expense............................................... (62,897) (41,694) ----------- ----------- Future net cash flows................................................... 194,604 129,123 Less 10% annual discount for estimated timing of cash flows........... (116,896) (80,521) ----------- ----------- Standardized measure of discounted future net cash flows.............. $ 77,708 $ 48,602 =========== ===========
The future cash flows estimated to be spent to develop proved undeveloped properties in the years ended September 30, 2004, 2005 and 2006 are $27.4 million, $28.2 million and $15.6 million, respectively. F-27 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED) NOTE 9 - SUPPLEMENTAL OIL AND GAS INFORMATION - (CONTINUED) The following table summarizes the changes in the standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes (unaudited):
Years Ended September 30, ----------------------------- 2003 2002 ----------- ----------- (in thousands) Balance, beginning of year.............................................. $ 48,602 $ 53,240 Increase (decrease) in discounted future net cash flows: Sales and transfers of oil and gas, net of related costs.............. (14,099) (8,513) Net changes in prices and production costs............................ 20,455 (6,038) Revisions of previous quantity estimates.............................. 3,678 (5,633) Development costs incurred............................................ 3,689 3,555 Changes in future development costs................................... (158) (149) Transfers to limited partnerships..................................... (3,326) (4,047) Extensions, discoveries, and improved recovery less related costs...................................................... 24,574 11,049 Accretion of discount................................................. 17,082 6,653 Net changes in future income taxes.................................... (21,202) 1,107 Other................................................................. (1,587) (2,622) ----------- ----------- Balance, end of year.................................................... $ 77,708 $ 48,602 =========== ===========
F-28 CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) ATLAS RESOURCES, INC. AND SUBSIDIARY MARCH 31, 2004 F-29 ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS (in thousands, except share data)
MARCH 31, SEPTEMBER 30, 2004 2003 ------------ ----------- (Unaudited) (Audited) ASSETS Current assets: Cash and cash equivalents........................................................ $ 433 $ 4,702 Accounts receivable.............................................................. 5,419 4,895 Other current assets............................................................. 650 532 ------------ ----------- Total current assets......................................................... 6,502 10,129 Property and equipment: Oil and gas properties and equipment (successful efforts)........................ 98,007 85,199 Buildings and land............................................................... 2,879 2,830 Other............................................................................ 367 414 ------------ ----------- 101,253 88,443 Less - accumulated depreciation, depletion and amortization...................... (19,985) (16,388) ------------- ----------- Net property and equipment....................................................... 81,268 72,055 Goodwill ...................................................................... 20,868 20,868 Operating and management contracts (less accumulated amortization of $2,670 and $2,431)............................. 3,683 3,922 ------------ ----------- Total assets................................................................. $ 112,321 $ 106,974 ============ =========== LIABILITIES AND STOCKHOLDER'S EQUITY Current liabilities: Current portion of long-term debt................................................ $ 56 $ 56 Accounts payable and accrued liabilities......................................... 6,184 7,098 Deferred revenue on drilling contracts........................................... 15,465 22,157 Advances and note from Parent.................................................... 63,272 51,150 ------------ ----------- Total current liabilities.................................................... 84,977 80,461 Long-term debt...................................................................... 110 138 Asset retirement obligation......................................................... 809 701 Stockholder's equity: Common stock - stated value $10 per share; 500 authorized shares; 200 shares issued and outstanding....................... 2 2 Additional paid-in capital....................................................... 16,505 16,505 Retained earnings................................................................ 9,918 9,167 ------------ ----------- Total stockholder's equity................................................. 26,425 25,674 ----------- ----------- $ 112,321 $ 106,974 ============ ===========
See accompanying notes to consolidated financial statements F-30 ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED STATEMENTS OF INCOME SIX MONTHS ENDED MARCH 31, 2004 AND 2003 (UNAUDITED) (in thousands)
2004 2003 ------------ ----------- REVENUES Well drilling........................................................................ $ 48,207 $ 29,949 Gas and oil production............................................................... 10,456 7,359 Well services........................................................................ 1,939 1,559 Transportation....................................................................... 1,259 1,224 Other ............................................................................ 104 75 ------------ ----------- 61,965 40,166 COSTS AND EXPENSES Well drilling......................................................................... 41,919 26,043 Gas and oil production and exploration................................................ 1,963 908 Well services......................................................................... 573 576 Non-direct............................................................................ 11,375 8,450 Depreciation, depletion and amortization.............................................. 3,900 2,356 Accretion of asset retirement obligation.............................................. 25 99 Interest ............................................................................. 1,259 1,179 ------------ ----------- Total costs and expenses..................................................... 61,014 39,611 ------------ ----------- Income from operations before income taxes............................................ 951 555 Provision for income taxes............................................................ 200 79 ------------ ----------- Net income............................................................................ $ 751 $ 476 ============ ===========
ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDER'S EQUITY SIX MONTHS ENDED MARCH 31, 2004 (UNAUDITED) (in thousands, except share data) Common stock Additional Totals -------------------------- Paid-In Retained Stockholder's Shares Amount Capital Earnings Equity -------------------------------------------------------------------- Balance, October 1, 2003.................. 200 $ 2 $ 16,505 $ 9,167 $ 25,674 Net income................................ 751 751 -------- ----------- ------------ ------- ----------- Balance, March 31, 2004................... 200 $ 2 $ 16,505 $ 9,918 $ 26,425 ======== ========= ============ ========= ===========
See accompanying notes to consolidated financial statements F-31 ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME SIX MONTHS ENDED MARCH 31, 2004 AND 2003 (UNAUDITED) (in thousands)
2004 2003 ---------- ----------- Net income................................................................. $ 751 $ 476 Cash flow hedge losses reclassed into gas sales, net of taxes of $76....................................................... - 468 Change in fair value of cash flow hedges, net of taxes of $151...................................................... - (927) ---------- ------------ Comprehensive income....................................................... $ 751 $ 17 =========== ===========
ATLAS RESOURCES, INC. AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS SIX MONTHS ENDED MARCH 31, 2004 AND 2003 (UNAUDITED) (in thousands)
2004 2003 ------------- ------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income.......................................................................... $ 751 $ 476 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization......................................... 3,900 2,356 Accretion of asset retirement obligation......................................... 25 99 Gain on asset sale............................................................... (19) - License fees and interest on intercompany note due to parent..................... 15,187 9,200 Change in operating assets and liabilities.......................................... (8,289) (2,315) ------------ ------------ Net cash provided by operating activities........................................... 11,555 14,446 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures................................................................ (12,704) (9,424) Proceeds-from asset sales........................................................... 33 - ----------- ----------- Net cash used in investing activities............................................... (12,671) (9,424) CASH FLOWS FROM FINANCING ACTIVITIES: Borrowings - long-term debt......................................................... - 229 Payments - long-term debt........................................................... (28) (7) Advances to Parent and Affiliates................................................... (3,125) (1,929) ------------ ------------ Net cash used in financing activities............................................... (3,153) (1,707) ------------ ------------ (Decrease) increase in cash and cash equivalents.................................... (4,269) 3,315 Cash and cash equivalents at beginning of year...................................... 4,702 698 ----------- ----------- Cash and cash equivalents at end of year............................................ $ 433 $ 4,013 =========== ===========
See accompanying notes to consolidated financial statements F-32 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS MARCH 31, 2004 (Unaudited) NOTE 1 - INTERIM FINANCIAL STATEMENTS The consolidated financial statements of Atlas Resources, Inc. and its wholly-owned subsidiary (the "Company") as of March 31, 2004 and for the six months ended March 31, 2004 and 2003, are unaudited. These consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("US GAAP") for interim financial information and certain rules and regulations of the Securities and Exchange Commission. Accordingly, they do not include all of the information and footnotes required by US GAAP for complete financial statements. The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect (i) the reported amounts of assets and liabilities, (ii) disclosure of contingent assets and liabilities as of the dates of the financial statements and (iii) the reported amounts of revenues and expenses during the reporting periods. In the opinion of management, all adjustments (consisting only of normal recurring adjustments and certain cost allocations for expenses paid by either the Parent or its' affiliates on behalf of the Company) considered necessary for a fair presentation have been reflected in these consolidated financial statements. Operating results for the six months ended March 31, 2004, are not necessarily indicative of the results that may be expected for the year ending September 30, 2004. Certain reclassifications have been made in the fiscal 2003 consolidated financial statements to conform to the fiscal 2004 presentation. These financial statements should be read in conjunction with the Company's audited September 30, 2003 consolidated financial statements. NOTE 2 - CONSOLIDATED STATEMENTS OF CASH FLOWS Supplemental disclosure of cash flow information:
Six Months Ended ---------------- March 31, --------- 2004 2003 ----------- -------- (in thousands) CASH PAID DURING THE YEARS FOR: Interest..................................................................... $ - $ 250 Income taxes (refunded) paid................................................. $ - $ - NON-CASH ACTIVITIES INCLUDE THE FOLLOWING: Asset Retirement Obligations incurred........................................ $ 101 $ -
F-33 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED MARCH 31, 2004 (Unaudited) NOTE 3 - ASSET RETIREMENT OBLIGATIONS The Company accounts for the estimated plugging and abandonment of its oil and gas properties in accordance with Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement obligations". A reconciliation of the Company's liability for well plugging and abandonment costs for the six months ended March 31, 2004 and 2003 is as follows (in thousands):
2004 2003 ---- ---- Asset retirement obligations, beginning of period.......................................... $ 701 $ - Adoption of SFAS 143, effective October 1, 2002............................................ - 602 Liabilities incurred....................................................................... 101 - Liabilities settled........................................................................ (41) - Revision in estimates...................................................................... 23 - Accretion expense.......................................................................... 25 99 --------- --------- Asset retirement obligations, end of period................................................ $ 809 $ 701 ======== ========
NOTE 4 - COMMITMENTS AND CONTINGENCIES The Company is the managing general partner of various energy partnerships, and has agreed to indemnify each investor partner from any liability that exceeds such partner's share of partnership assets. Subject to certain conditions, investor partners in certain energy partnerships have the right to present their interests for purchase by the Company, as managing general partner. The Company is not obligated to purchase more than 5% or 10% of the units in any calendar year. Based on past experience, the Company believes that any liability incurred would not be material. The Company may be required to subordinate a part of its net partnership revenues 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. The Company is party to various routine legal proceedings arising out of the ordinary course of its business. Management believes that none of these actions, individually or in the aggregate, will have a material adverse effect on the Company's financial condition or operations F-34 ATLAS RESOURCES, INC. AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - CONTINUED MARCH 31, 2004 (Unaudited) NOTE 5 - DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES The Company from time to time enters into natural gas futures and option contracts to hedge its exposure to changes in natural gas prices. At any point in time, such contracts may include regulated New York Mercantile Exchange ("NYMEX") futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas. The Company formally documents all relationships between hedging instruments and the items being hedged, including the Company's risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. The Company assesses, both at the inception of the hedge and on an ongoing basis, whether the derivatives are highly effective in offsetting changes in the fair value of hedged items. Historically these contracts have qualified and been designated as cash flow hedges and recorded at their fair values. Gains or losses on future contracts are determined as the difference between the contract price and a reference price, generally prices on NYMEX. Such gains and losses are charged or credited to accumulated other comprehensive income (loss) and recognized as a component of sales revenue in the month the hedged gas is sold. If it is determined that a derivative is not highly effective as a hedge or it has ceased to be a highly effective hedge, due to the loss of correlation between changes in gas reference prices under a hedging instrument and actual gas prices, the Company will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings. At March 31, 2004, the Company had no open natural gas futures contracts related to natural gas sales and accordingly, had no unrealized loss or gain related to open NYMEX contracts at that date. The company did not settle any contracts during the six months ended March 31, 2004. The Company recognized losses of $544,000 on settled contracts during the six months ended March 31, 2003. The Company recognized no gains or losses during the six months ended March 31, 2004 and 2003 for hedge ineffectiveness or as a result of the discontinuance of cash flow hedges. Although hedging provides the Company some protection against falling prices, these activities could also reduce the potential benefits of price increases, depending upon the instrument. NOTE 6- EFFECTIVE TAX RATE The Company is included in the consolidated federal income tax return of RAI. Income taxes are presented as if the Company had filed a return on a separate company basis utilizing their calculated effective rate of 21% and 14% for the six months ended March 31, 2004 and 2003 respectively. The Company's effective tax rate is lower than the federal statutory rate due to the benefit of percentage depletion and fuel credits. Deferred taxes, which are included in Advances from Parent, reflect the tax effect of 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. F-35 APPENDIX A INFORMATION REGARDING CURRENTLY PROPOSED PROSPECTS FOR ATLAS AMERICA PUBLIC #14-2004 L.P. INFORMATION REGARDING CURRENTLY PROPOSED PROSPECTS The partnerships do not currently hold any interests in any prospects on which the wells will be drilled, and the managing general partner has absolute discretion in determining which prospects will be acquired to be drilled. However, set forth below is information relating to approximately ___ proposed prospects and the wells which will be drilled on the prospects by Atlas America Public #14-2004 L.P., which is the first partnership in the program and must be closed by December 31, 2004. It is referred to in this section as the "2004 Partnership." One well will be drilled on each development prospect, and for purposes of this section the well and prospect are referred to together as the "well." Although the managing general partner does not anticipate that the wells will be selected in the order in which they are set forth below, these wells are currently proposed to be drilled by the 2004 Partnership when the subscription proceeds are released from escrow and from time to time thereafter subject to the managing general partner's right to: o withdraw the wells and to substitute other wells; o take a lesser working interest in the wells; o add other wells; or o any combination of the foregoing. The specified wells represent the necessary wells if approximately $___ million is raised and the 2004 Partnership takes the working interest in the wells which is set forth below in the "Lease Information" for each well. The managing general partner has not proposed any other wells if: o a greater amount of subscription proceeds is raised; o a lesser working interest in the wells is acquired; or o the wells are substituted for any of the reasons set forth below. The managing general partner has not authorized any person to make any representations to you concerning the possible inclusion of any other wells which will be drilled by the 2004 Partnership or any of the other partnerships, and you should rely only on the information in this prospectus. The currently proposed wells will be assigned unless there are circumstances which, in the managing general partner's opinion, lessen the relative suitability of the wells. These considerations include: o the amount of the subscription proceeds received in the 2004 Partnership; o the latest geological and production data available; o potential title or spacing problems; o availability and price of drilling services, tubular goods and services; o approvals by federal and state departments or agencies; o agreements with other working interest owners in the wells; o farmins; and o continuing review of other properties which may be available. Any substituted and/or additional wells will meet the same general criteria for 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 production and geological information for the substituted and/or additional wells. 1 The purpose of the information regarding the currently proposed wells is to help you evaluate the economic potential and risks of drilling the proposed wells. This includes production information for wells in the general area of the proposed well which the managing general partner believes is an important indicator in evaluating the economic potential of any well to be drilled. However, a well drilled by the 2004 Partnership may not 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. Also, the managing general partner has not been able to obtain production information for previously drilled wells in the immediate areas where a portion of the currently proposed wells in Pennsylvania are situated because the information is not available to the managing general partner as discussed in "Risk Factors - Risks Related to an Investment In a Partnership - Lack of Production Information Increases Your Risk and Decreases Your Ability to Evaluate the Feasibility of a Partnership's Drilling Program." These wells, for which no production data for other wells in the immediate area are available to the managing general partner, have been proposed by the managing general partner to be drilled because geologic trends in the immediate area, such as sand thickness, porosities and water saturations, lead the managing general partner to believe that the proposed wells also will be productive. When reviewing production information for each well offsetting or in the general area of a proposed well to be drilled you should consider the factors set forth below. o The length of time that the well has been on-line, and the period for which production information is shown. Generally, the shorter the period for which production information is shown the less reliable the production information. o Production from a well declines throughout the life of the well. The rate of decline, the "decline curve," varies based on which geological formation is producing, and may be affected by the operation of the well. For example, the wells in the Clinton/Medina geological formation will have a different decline curve from the wells in the Mississippian/Upper Devonian Sandstone Reservoir in Fayette and Green Counties. Also, each well in the Clinton/Medina geological formation or the Mississippian/Upper Devonian Sandstone Reservoirs will have a different rate of decline from the other wells in the same formation or reservoirs. o The greatest volume of production ("flush production") from a well usually occurs in the early period of well operations and may indicate a greater reserve volume than the well actually will produce. This period of flush production can vary depending on how the well is operated and the location of the well. o The production information for some wells is incomplete or very limited. The designation "N/A" means: o the production information was not available to the managing general partner for the reasons discussed in "Risk Factors - Risks Related to an Investment In a Partnership - Lack of Production Information Increases Your Risk and Decreases Your Ability to Evaluate the Feasibility of a Partnership's Drilling Program"; or o if the managing general partner was the operator, then when the information was prepared the well was: o not completed; o not on-line to sell production; or o producing for only a short period of time. o Production information for wells located close to a proposed well tends to be more relevant than production information for wells located farther away, although performance and volume of production from wells located on contiguous prospects can be much different. o Consistency in production among wells tends to confirm the reliability and predictability of the production. 2 To help you become familiar with the proposed wells the information set forth below is included. o A map of western Pennsylvania and eastern Ohio showing their counties.......................................................... o Fayette County, Pennsylvania (Mississippian/Upper Devonian Sandstone Reservoirs) o Lease information for Fayette and Greene Counties, Pennsylvania............................................. o Location and Production Maps for Fayette and Greene Counties, Pennsylvania showing the proposed wells and the wells in the area........................................ o Production data for Fayette and Greene Counties, Pennsylvania............................................. o United Energy Development Consultants, Inc.'s geologic evaluation for Fayette and Greene Counties, Pennsylvania............................................. o Western Pennsylvania (Clinton/Medina Geological Formation) o Lease information for western Pennsylvania and eastern Ohio..................................................... o Location and Production Map for western Pennsylvania and eastern Ohio showing the proposed wells and the wells in the area................................................. o Production data for western Pennsylvania and eastern Ohio..................................................... o United Energy Development Consultants, Inc.'s geologic evaluation for western Pennsylvania and eastern Ohio..................................................... o Armstrong County, Pennsylvania (Upper Devonian Sandstone Reservoirs) o Lease information for Armstrong and Indiana Counties, Pennsylvania............................................. o Location and Production Map for Armstrong and Indiana Counties, Pennsylvania showing the proposed wells and the wells in the area........................................ o Production data for Armstrong and Indiana Counties, Pennsylvania............................................. o United Energy Development Consultants, Inc.'s geologic evaluation for Armstrong and Indiana Counties, Pennsylvania............................................. o McKean County, Pennsylvania (Upper Devonian Sandstone Reservoirs) o Lease information for McKean County, Pennsylvania........ o Location and Production Map for McKean County, Pennsylvania showing the proposed wells and the wells in the area................................................. o Production data for McKean County, Pennsylvania.......... o United Energy Development Consultants, Inc.'s geologic evaluation for McKean County, Pennsylvania............... 3 MAP OF WESTERN PENNSYLVANIA AND EASTERN OHIO 4 [GRAPHIC OMITTED][GRAPHIC OMITTED] 5 [TO BE PROVIDED BY PRE-EFFECTIVE AMENDMENT] LEASE INFORMATION FOR FAYETTE AND GREENE COUNTIES, PENNSYLVANIA 6 [TO BE PROVIDED BY PRE-EFFECTIVE AMENDMENT] LOCATION AND PRODUCTION MAPS FOR FAYETTE AND GREENE COUNTIES, PENNSYLVANIA 7 [TO BE PROVIDED BY PRE-EFFECTIVE AMENDMENT] PRODUCTION DATA FOR FAYETTE AND GREENE COUNTIES, PENNSYLVANIA 8 [TO BE PROVIDED BY PRE-EFFECTIVE AMENDMENT] UEDC'S GEOLOGIC EVALUATION FOR THE CURRENTLY PROPOSED WELLS IN FAYETTE AND GREENE COUNTIES, PENNSYLVANIA 9 [TO BE PROVIDED BY PRE-EFFECTIVE AMENDMENT] LEASE INFORMATION FOR WESTERN PENNSYLVANIA AND EASTERN OHIO 10 [TO BE PROVIDED BY PRE-EFFECTIVE AMENDMENT] LOCATION AND PRODUCTION MAP FOR WESTERN PENNSYLVANIA AND EASTERN OHIO 11 [TO BE PROVIDED BY PRE-EFFECTIVE AMENDMENT] PRODUCTION DATA FOR WESTERN PENNSYLVANIA AND EASTERN OHIO 12 [TO BE PROVIDED BY PRE-EFFECTIVE AMENDMENT] UEDC'S GEOLOGIC EVALUATION FOR THE CURRENTLY PROPOSED WELLS IN WESTERN PENNSYLVANIA AND EASTERN OHIO 13 [TO BE PROVIDED BY PRE-EFFECTIVE AMENDMENT] LEASE INFORMATION FOR ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA 14 [TO BE PROVIDED BY PRE-EFFECTIVE AMENDMENT] LOCATION AND PRODUCTION MAP FOR ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA 15 [TO BE PROVIDED BY PRE-EFFECTIVE AMENDMENT] PRODUCTION DATA FOR ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA 16 [TO BE PROVIDED BY PRE-EFFECTIVE AMENDMENT] UEDC'S GEOLOGIC EVALUATION FOR THE CURRENTLY PROPOSED WELLS IN ARMSTRONG AND INDIANA COUNTIES, PENNSYLVANIA 17 [TO BE PROVIDED BY PRE-EFFECTIVE AMENDMENT] LEASE INFORMATION FOR MCKEAN COUNTY, PENNSYLVANIA 18 [TO BE PROVIDED BY PRE-EFFECTIVE AMENDMENT] LOCATION AND PRODUCTION MAP FOR MCKEAN COUNTY, PENNSYLVANIA 19 [TO BE PROVIDED BY PRE-EFFECTIVE AMENDMENT] PRODUCTION DATA FOR MCKEAN COUNTY, PENNSYLVANIA 20 [TO BE PROVIDED BY PRE-EFFECTIVE AMENDMENT] UEDC'S GEOLOGIC EVALUATION FOR THE CURRENTLY PROPOSED WELLS IN MCKEAN COUNTY, PENNSYLVANIA 21 EXHIBIT (A) FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP FOR ATLAS AMERICA PUBLIC #14-2004 L.P. [FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP FOR ATLAS AMERICA PUBLIC #14-2005(___) L.P.] TABLE OF CONTENTS SECTION NO. DESCRIPTION PAGE I. FORMATION 1.01 Formation....................................1 1.02 Certificate of Limited Partnership...........1 1.03 Name, Principal Office and Residence.........1 1.04 Purpose......................................1 II. DEFINITION OF TERMS 2.01 Definitions..................................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 of the Managing General Partner.........................12 3.05 Payment of Subscriptions....................13 3.06 Partnership Funds...........................13 IV. CONDUCT OF OPERATIONS 4.01 Acquisition of Leases.......................14 4.02 Conduct of Operations.......................16 4.03 General Rights and Obligations of the Participants and Restricted and Prohibited Transactions.................19 4.04 Designation, Compensation and Removal of Managing General Partner and Removal of Operator.........29 4.05 Indemnification and Exoneration.............32 4.06 Other Activities............................34 V. PARTICIPATION IN COSTS AND REVENUES, CAPITAL ACCOUNTS, ELECTIONS AND DISTRIBUTIONS 5.01 Participation in Costs and Revenues.........35 5.02 Capital Accounts and Allocations Thereto.................................38 5.03 Allocation of Income, Deductions and Credits.................................39 5.04 Elections...................................41 5.05 Distributions...............................41 VI. TRANSFER OF INTERESTS 6.01 Transferability.............................42 6.02 Special Restrictions on Transfers...........43 6.03 Right of Managing General Partner to Hypothecate and/or Withdraw Its Interests...44 6.04 Presentment.................................44 VII. DURATION, DISSOLUTION, AND WINDING UP 7.01 Duration....................................46 7.02 Dissolution and Winding Up..................47 VIII. MISCELLANEOUS PROVISIONS 8.01 Notices.....................................47 8.02 Time........................................48 8.03 Applicable Law..............................48 8.04 Agreement in Counterparts...................48 8.05 Amendment...................................48 8.06 Additional Partners.........................49 8.07 Legal Effect................................49 EXHIBITS EXHIBIT (I-A) - Form of Managing General Partner Signature Page EXHIBIT (I-B) - Form of Subscription Agreement EXHIBIT (II) - Form of Drilling and Operating Agreement for Atlas America Public #14-2004 L.P. [Atlas America Public #14-2005 (___) L.P.] FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP FOR ATLAS AMERICA PUBLIC #14-2004 L.P. [FORM OF AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP FOR ATLAS AMERICA PUBLIC #14-2005(_____) L.P.] THIS AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP ("AGREEMENT"), amending and restating the original Certificate of Limited Partnership, is made and entered into as of _____________________, 2004, by and among Atlas Resources, Inc., referred to as "Atlas" or the "Managing General Partner," and the remaining parties from time to time signing a Subscription Agreement for Limited Partner Units, these parties sometimes referred to as "Limited Partners," or for Investor General Partner Units, these parties sometimes referred to as "Investor General Partners." ARTICLE I FORMATION 1.01. FORMATION. The parties have formed a limited partnership under the Delaware Revised Uniform Limited Partnership Act on the terms and conditions set forth in this Agreement. 1.02. CERTIFICATE OF LIMITED PARTNERSHIP. This document is not only an agreement among the parties, but also is the Amended and Restated Certificate and Agreement of Limited Partnership of the Partnership. This document shall be filed or recorded in the public offices required under applicable law or deemed advisable in the discretion of the Managing General Partner. Amendments to the certificate of limited partnership shall be filed or recorded in the public offices required under applicable law or deemed advisable in the discretion of the Managing General Partner. 1.03. NAME, PRINCIPAL OFFICE AND RESIDENCE. 1.03(a). NAME. The name of the Partnership is Atlas America Public #14-2004 L.P. [Atlas America Public #14-2005(_____) L.P.]. 1.03(b). RESIDENCE. The residence of the Managing General Partner is 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 the Participant. All addresses shall be subject to change on notice to the parties. 1.03(c). AGENT FOR SERVICE OF PROCESS. The name and address of the agent for service of process shall be Andrew M. Lubin at 110 S. Poplar Street, Suite 101, Wilmington, Delaware 19801. 1.04. PURPOSE. The Partnership shall engage in all phases of the natural gas and oil business. This includes, without limitation, exploration for, development and production of natural gas and oil on the terms and conditions set forth below and any other proper purpose under the Delaware Revised Uniform Limited Partnership Act. The Managing General Partner may not, without the affirmative vote of Participants whose Units equal a majority of the total Units, do the following: (i) change the investment and business purpose of the Partnership; or (ii) cause the Partnership to engage in activities outside the stated business purposes of the Partnership through joint ventures with other entities. 1 ARTICLE II DEFINITION OF TERMS 2.01. DEFINITIONS. As used in this Agreement, the following terms shall have the meanings set forth below: 1. "Administrative Costs" means all customary and routine expenses incurred by the Sponsor for the conduct of Partnership administration, including: in-house legal, finance, in-house accounting, secretarial, travel, office rent, telephone, data processing and other items of a similar nature. Administrative Costs shall be limited as follows: (i) no Administrative Costs charged shall be duplicated under any other category of expense or cost; and (ii) no portion of the salaries, benefits, compensation or remuneration of controlling persons of the Managing General Partner shall be reimbursed by the Partnership as Administrative Costs. Controlling persons include directors, executive officers and those holding 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" means the official or agency administering the securities laws of a state. 3. "Affiliate" means with respect to a specific person: (i) any person directly or indirectly owning, controlling, or holding with power to vote 10% or more of the outstanding voting securities of the specified person; (ii) any person 10% or more of whose outstanding voting securities are directly or indirectly owned, controlled, or held with power to vote, by the specified person; (iii) any person directly or indirectly controlling, controlled by, or under common control with the specified person; (iv) any officer, director, trustee or partner of the specified person; and (v) if the specified person is an officer, director, trustee or partner, any person for which the person acts in any such capacity. 4. "Agreement" means this Amended and Restated Certificate and Agreement of Limited Partnership, including all exhibits to this Agreement. 5. "Anthem Securities" means Anthem Securities, Inc., whose principal executive offices are located at 311 Rouser Road, P.O. Box 926, Moon Township, Pennsylvania 15108-0926. 6. "Assessments" means additional amounts of capital which may be mandatorily required of or paid voluntarily by a Participant beyond his subscription commitment. 7. "Atlas" means Atlas Resources, Inc., a Pennsylvania corporation, whose principal executive offices are located at 311 Rouser Road, Moon Township, Pennsylvania 15108. 8. "Atlas America Public #14-2004 Program" means a series of up to three limited partnerships entitled Atlas America Public #14-2004 L.P., Atlas America Public #14-2005(A) L.P. and Atlas America Public #14-2005(B) L.P. 9. "Capital Account" or "account" means the account established for each party, maintained as provided in ss.5.02 and its subsections. 2 10. "Capital Contribution" means the amount agreed to be contributed to the Partnership by a Partner pursuant to ss.ss.3.04 and 3.05 and their subsections. 11. "Carried Interest" means an equity interest in the Partnership issued to a Person without consideration, in the form of cash or tangible property, in an amount proportionately equivalent to that received from the Participants. 12. "Code" means the Internal Revenue Code of 1986, as amended. 13. "Cost," when used with respect to the sale or transfer of property to the Partnership, means: (i) the sum of the prices paid by the seller or transferor to an unaffiliated person for the property, including bonuses; (ii) title insurance or examination costs, brokers' commissions, filing fees, recording costs, transfer taxes, if any, and like charges in connection with the acquisition of the property; (iii) a pro rata portion of the seller's or transferor's actual necessary and reasonable expenses for seismic and geophysical services; and (iv) rentals and ad valorem taxes paid by the seller or transferor for the property to the date of its transfer to the buyer, interest and points actually incurred on funds used to acquire or maintain the property, and the portion of the seller's or transferor's reasonable, necessary and actual expenses for geological, engineering, drafting, accounting, legal and other like services allocated to the property cost in conformity with generally accepted accounting principles and industry standards, except for expenses in connection with the past drilling of wells which are not producers of sufficient quantities of oil or gas to make commercially reasonable their continued operations, and provided that the expenses enumerated in this subsection (iv) shall have been incurred not more than 36 months before the sale or transfer to the Partnership. "Cost," when used with respect to services, means the reasonable, necessary and actual expense incurred by the seller on behalf of the Partnership in providing the services, determined in accordance with generally accepted accounting principles. As used elsewhere, "Cost" means the price paid by the seller in an arm's-length transaction. 14. "Dealer-Manager" means: (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" means a well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic Horizon known to be productive. 16. "Direct Costs" means all actual and necessary costs directly incurred for the benefit of the Partnership and generally attributable to the goods and services provided to the Partnership by parties other than the Sponsor or its Affiliates. Direct Costs may not include any cost otherwise classified as Organization and Offering Costs, Administrative Costs, Intangible Drilling Costs, Tangible Costs, Operating Costs or costs related to the Leases, but may include the cost of services provided by the Sponsor or its Affiliates if the services are provided pursuant to written contracts and in compliance with ss.4.03(d)(7) or pursuant to the Managing General Partner's role as Tax Matters Partner. 3 17. "Distribution Interest" means an undivided interest in the Partnership's assets after payments to the Partnership's creditors or the creation of a reasonable reserve therefor, in the ratio the positive balance of a party's Capital Account bears to the aggregate positive balance of the Capital Accounts of all of the parties determined after taking into account all Capital Account adjustments for the taxable year during which liquidation occurs (other than those made pursuant to liquidating distributions or restoration of deficit Capital Account balances). Provided, however, after the Capital Accounts of all of the parties have been reduced to zero, the interest in the remaining Partnership assets shall equal a party's interest in the related Partnership revenues as set forth inss.5.01 and its subsections of this Agreement. 18. "Drilling and Operating Agreement" means the proposed Drilling and Operating Agreement between the Managing General Partner or an Affiliate as Operator, and the Partnership as Developer, a copy of the proposed form of which is attached to this Agreement as Exhibit (II). 19. "Exploratory Well" means a well drilled to: (i) find commercially productive hydrocarbons in an unproved area; (ii) find a new commercially productive Horizon in a field previously found to be productive of hydrocarbons at another Horizon; or (iii) significantly extend a known prospect. 20. "Farmout" means an agreement by the owner of the leasehold or Working Interest to assign his interest in certain acreage or well to the assignees, retaining some interest such as an Overriding Royalty Interest, an oil and gas payment, offset acreage or other type of interest, subject to the drilling of one or more specific wells or other performance as a condition of the assignment. 21. "Final Terminating Event" means any one of the following: (i) the expiration of the Partnership's fixed term; (ii) notice to the Participants by the Managing General Partner of its election to terminate the Partnership's affairs; (iii) notice by the Participants to the Managing General Partner of their similar election through the affirmative vote of Participants whose Units equal a majority of the total Units; or (iv) the termination of the Partnership under ss.708(b)(1)(A) of the Code or the Partnership ceases to be a going concern. 22. "Horizon" means a zone of a particular formation; that part of a formation of sufficient porosity and permeability to form a petroleum reservoir. 23. "Independent Expert" means a person with no material relationship to the Sponsor or its Affiliates who is qualified and in the business of rendering opinions regarding the value of natural gas and oil properties based on the evaluation of all pertinent economic, financial, geologic and engineering information available to the Sponsor or its Affiliates. 24. "Initial Closing Date" means the date after the minimum amount of subscription proceeds has been received when subscription proceeds are first withdrawn from the escrow account. 25. "Intangible Drilling Costs" or "Non-Capital Expenditures" means those expenditures associated with property acquisition and the drilling and completion of natural gas and oil wells that under present law are generally accepted as fully deductible currently for federal income tax purposes. This includes all expenditures made for any well before production in commercial quantities for wages, fuel, repairs, hauling, supplies and other costs and expenses incident to and necessary for drilling the well and preparing the well for production of natural gas or oil, that are currently deductible pursuant to Section 263(c) of the Code and Treasury Reg. Section 1.612-4, and are generally termed "intangible drilling and development costs," including the expense of plugging and abandoning any well before a completion attempt. 4 26. "Interim Closing Date" means those date(s) after the Initial Closing Date, but before the Offering Termination Date, that the Managing General Partner, in its sole discretion, applies additional subscription proceeds to additional Partnership activities, including drilling activities. 27. "Investor General Partners" means: (i) the persons signing the Subscription Agreement as Investor General Partners; and (ii) the Managing General Partner to the extent of any optional subscription as an Investor General Partner under ss.3.03(b)(2). All Investor General Partners shall be of the same class and have the same rights. 28. "Landowner's Royalty Interest" means an interest in production, or its proceeds, to be received free and clear of all costs of development, operation, or maintenance, reserved by a landowner on the creation of a Lease. 29. "Leases" means full or partial interests in natural gas and oil leases, oil and natural gas mineral rights, fee rights, licenses, concessions, or other rights under which the holder is entitled to explore for and produce oil and/or natural gas, and includes any contractual rights to acquire any such interest. 30. "Limited Partners" means: (i) the persons signing the Subscription Agreement as Limited Partners; (ii) the Managing General Partner to the extent of any optional subscription as a Limited Partner under ss.3.03(b)(2); (iii) the Investor General Partners on the conversion of their Investor General Partner Units to Limited Partner Units pursuant to ss.6.01(b); and (iv) any other persons who are admitted to the Partnership as additional or substituted Limited Partners. Except as provided in ss.3.05(b), with respect to the required additional Capital Contributions of Investor General Partners, all Limited Partners shall be of the same class and have the same rights. 31. "Managing General Partner" means: (i) Atlas Resources, Inc.; or (ii) any Person admitted to the Partnership as a general partner other than as an Investor General Partner who is designated to exclusively supervise and manage the operations of the Partnership. 32. "Managing General Partner Signature Page" means an execution and subscription instrument in the form attached as Exhibit (I-A) to this Agreement, which is incorporated in this Agreement by reference. 33. "Offering Termination Date" means the date after the minimum amount of subscription proceeds has been received on which the Managing General Partner determines, in its sole discretion, the Partnership's subscription period is closed and the acceptance of subscriptions ceases, which shall not be later than December 31, 2004. [December 31, 2005 with respect to Partnerships designated "Atlas America Public #14-2005(_____) L.P."] 5 Notwithstanding the above, the Offering Termination Date may not extend beyond the time that subscriptions for the maximum number of Units set forth in ss.3.03(c)(1) have been received and accepted by the Managing General Partner. 34. "Operating Costs" means expenditures made and costs incurred in producing and marketing natural gas or oil from completed wells. These costs include, but are not limited to: (i) labor, fuel, repairs, hauling, materials, supplies, utility charges and other costs incident to or related to producing and marketing natural gas and oil; (ii) ad valorem and severance taxes; (iii) insurance and casualty loss expense; and (iv) compensation to well operators or others for services rendered in conducting these operations. Operating Costs also include reworking, workover, subsequent equipping, and similar expenses relating to any well, but do not include the costs to re-enter and deepen an existing well, complete the well to deeper reservoirs or plug the well if it is nonproductive from the targeted deeper reservoirs. 35. "Operator" means 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. 36. "Organization and Offering Costs" means all costs of organizing and selling the offering including, but not limited to: (i) total underwriting and brokerage discounts and commissions (including fees of the underwriters' attorneys); (ii) expenses for printing, engraving, mailing, salaries of employees while engaged in sales activities, charges of transfer agents, registrars, trustees, escrow holders, depositaries, engineers and other experts; (iii) expenses of qualification of the sale of the securities under federal and state law, including taxes and fees, accountants' and attorneys' fees; and (iv) other front-end fees. 37. "Organization Costs" means all costs of organizing the offering including, but not limited to: (i) 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; (ii) expenses of qualification of the sale of the securities under federal and state law, including taxes and fees, accountants' and attorneys' fees; and (iii) other front-end fees. 38. "Overriding Royalty Interest" means an interest in the natural gas and oil produced under a Lease, or the proceeds from the sale thereof, carved out of the Working Interest, to be received free and clear of all costs of development, operation, or maintenance. 39. "Participants" means: (i) the Managing General Partner to the extent of its optional subscription under ss.3.03(b)(2); 6 (ii) the Limited Partners; and (iii) the Investor General Partners. 40. "Partners" means: (i) the Managing General Partner; (ii) the Investor General Partners; and (iii) the Limited Partners. 41. "Partnership" means Atlas America Public #14-2004 L.P. [ Atlas America Public #14-2005(_____) L.P.]. 42. "Partnership Net Production Revenues" means gross revenues after deduction of the related Operating Costs, Direct Costs, Administrative Costs and all other Partnership costs not specifically allocated. 43. "Partnership Well" means a well, some portion of the revenues from which is received by the Partnership. 44. "Person" means a natural person, partnership, corporation, association, trust or other legal entity. 45. "Production Purchase" or "Income" Program means any program whose investment objective is to directly acquire, hold, operate, and/or dispose of producing oil and gas properties. Such a program may acquire any type of ownership interest in a producing property, including, but not limited to, working interests, royalties, or production payments. A program which spends at least 90% of capital contributions and funds borrowed (excluding offering and organizational expenses) in the above described activities is presumed to be a production purchase or income program. 46. "Program" means one or more limited or general partnerships or other investment vehicles formed, or to be formed, for the primary purpose of: (i) exploring for natural gas, oil and other hydrocarbon substances; or (ii) investing in or holding any property interests which permit the exploration for or production of hydrocarbons or the receipt of such production or its proceeds. 47. "Prospect" means an area covering lands which are believed by the Managing General Partner to contain subsurface structural or stratigraphic conditions making it susceptible to the accumulations of hydrocarbons in commercially productive quantities at one or more Horizons. The area, which may be different for different Horizons, shall be: (i) designated by the Managing General Partner in writing before the conduct of Partnership operations; and (ii) enlarged or contracted from time to time on the basis of subsequently acquired information to define the anticipated limits of the associated hydrocarbon reserves and to include all acreage encompassed therein. If the well to be drilled by the Partnership is to a Horizon containing Proved Reserves, then a "Prospect" for a particular Horizon may be limited to the minimum area permitted by state law or local practice, whichever is applicable, to protect against drainage from adjacent wells. Subject to the foregoing sentence, "Prospect" shall be deemed the drilling or spacing unit for the Clinton/Medina geological formation and the Mississippian and/or Upper Devonian Sandstone reservoirs in Ohio, Pennsylvania, and New York. 48. "Proved Developed Oil and Gas Reserves" means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. 7 49. "Proved Reserves" means the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. (i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes: (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. (ii) 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"; (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. 50. "Proved Undeveloped Reserves" means reserves that are expected to be recovered from either: (i) new wells on undrilled acreage; or (ii) from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. 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. 8 51. "Reimbursement for Permissible Non-Cash Compensation" means a .5% accountable reimbursement for permissible non-cash compensation, which includes: (i) an accountable reimbursement for training and education meetings for associated persons of the Selling Agents; (ii) gifts that do not exceed $100 per year and are not preconditioned on achievement of a sales target; (iii) an occasional meal, a ticket to a sporting event or the theater, or comparable entertainment which is neither so frequent nor so extensive as to raise any question of propriety and is not preconditioned on achievement of a sales target; and (iv) contributions to a non-cash compensation arrangement between a Selling Agent and its associated persons, provided that neither the Managing General Partner nor the Dealer-Manager directly or indirectly participates in the Selling Agent's organization of a permissible non-cash compensation arrangement. 52. "Roll-Up" means a transaction involving the acquisition, merger, conversion or consolidation, either directly or indirectly, of the Partnership and the issuance of securities of a Roll-Up Entity. The term does not include: (i) a transaction involving securities of the Partnership that have been listed for at least 12 months on a national exchange or traded through the National Association of Securities Dealers Automated Quotation National Market System; or (ii) a transaction involving the conversion to corporate, trust or association form of only the Partnership if, as a consequence of the transaction, there will be no significant adverse change in any of the following: (a) voting rights; (b) the Partnership's term of existence; (c) the Managing General Partner's compensation; and (d) the Partnership's investment objectives. 53. "Roll-Up Entity" means a partnership, trust, corporation or other entity that would be created or survive after the successful completion of a proposed roll-up transaction. 54. "Sales Commissions" means all underwriting and brokerage discounts and commissions incurred in the sale of Units payable to registered broker/dealers, but excluding the following: (i) the 2.5% Dealer-Manager fee; (ii) the .5% accountable Reimbursement for Permissible Non-Cash Compensation; and (iii) the up to .5% reimbursement for bona fide accountable due diligence expenses. 55. "Selling Agents" means those broker/dealers selected by the Dealer-Manager which will participate in the offer and sale of the Units. 56. "Sponsor" means any person directly or indirectly instrumental in organizing, wholly or in part, a program or any person who will manage or is entitled to manage or participate in the management or control of a program. The definition includes: 9 (i) the managing and controlling general partner(s) and any other person who actually controls or selects the person who controls 25% or more of the exploratory, development or producing activities of the program, or any segment thereof, even if that person has not entered into a contract at the time of formation of the program; and (ii) whenever the context so requires, the term "sponsor" shall be deemed to include its affiliates. "Sponsor" does not include wholly independent third-parties such as attorneys, accountants, and underwriters whose only compensation is for professional services rendered in connection with the offering of units. 57. "Subscription Agreement" means an execution and subscription instrument in the form attached as Exhibit (I-B) to this Agreement, which is incorporated in this Agreement by reference. 58. "Tangible Costs" or "Capital Expenditures" means those costs associated with drilling and completing natural gas and oil wells which are generally accepted as capital expenditures under the Code. This includes all of the following: (i) costs of equipment, parts and items of hardware used in drilling and completing a well; and (ii) those items necessary to deliver acceptable natural gas and oil production to purchasers to the extent installed downstream from the wellhead of any well and which are required to be capitalized under the Code and its regulations. 59. "Tax Matters Partner" means the Managing General Partner. 60. "Units" or "Units of Participation" means up to 625 Limited Partner interests and up to 11,875 Investor General Partner interests, which will be converted to Limited Partner Units as set forth in ss.6.01(b), purchased by Participants in the Partnership under the provisions of ss.3.03 and its subsections, including any rights to profits, losses, income, gain, credits, deductions, cash distributions or returns of capital or other attributes of the Units. 61. "Working Interest" means an interest in a Lease which is subject to some portion of the cost of development, operation, or maintenance of the Lease. ARTICLE III SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS 3.01. DESIGNATION OF MANAGING GENERAL PARTNER AND PARTICIPANTS. Atlas shall serve as Managing General Partner of the Partnership. Atlas shall further serve as a Participant to the extent of any subscription made by it pursuant to ss.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. On the admission of one or more Limited Partners, the Partnership shall return to the Original Limited Partner its Capital Contribution and shall reacquire its Unit. The Original Limited Partner shall then cease to be a Limited Partner in the Partnership with respect to 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 Subscription Agreements are accepted by the Managing General Partner if, after the admission of the additional Participants, the total Units do not exceed the maximum number of Units set forth in ss.3.03(c)(1). 10 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 amount of subscription proceeds set forth in ss.3.03(c)(2). Thereafter, subscriptions may be paid directly to the Partnership account. 3.03. SUBSCRIPTIONS TO THE PARTNERSHIP. 3.03(a). SUBSCRIPTIONS BY PARTICIPANTS. 3.03(a)(1). SUBSCRIPTION PRICE AND MINIMUM SUBSCRIPTION. The subscription price of a Unit in the Partnership shall be $10,000, except as set forth below, and shall be designated on each Participant's Subscription Agreement and payable as set forth in ss.3.05(b)(1). The minimum 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 subscriptions shall be accepted in $1,000 increments, beginning with $6,000, $7,000, etc. Notwithstanding the foregoing, the subscription price for: (i) the Managing General Partner, its officers, directors, and Affiliates, and Participants who buy Units through the officers and directors of the Managing General Partner, shall be reduced by an amount equal to a 2.5% Dealer-Manager fee, a 7% Sales Commission, a .5% accountable Reimbursement for Permissible Non-Cash Compensation, and a .5% reimbursement of the Selling Agents' bona fide accountable due diligence expenses, which shall not be paid with respect to these sales; and (ii) the subscription price for Registered Investment Advisors and their clients, and Selling Agents and their registered representatives and principals, shall be reduced by an amount equal to a 7% Sales Commission, which shall not be paid with respect to these sales. No more than 5% of the total Units, in the aggregate, shall be sold with the discounts described above. 3.03(a)(2). EFFECT OF SUBSCRIPTION. Execution of a Subscription Agreement shall serve as an agreement by the Participant to be bound by each and every term of this Agreement. 3.03(b). 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 ss.4.01(a)(4); and (ii) pay the costs or make the required contributions charged to it under this Agreement. These Capital Contributions shall be paid or made by the Managing General Partner at the time the costs are required to be paid by the Partnership, but no later than December 31, 2005 [December 31, 2006]. 3.03(b)(2). MANAGING GENERAL PARTNER'S OPTIONAL ADDITIONAL SUBSCRIPTION. In addition to the Managing General Partner's required subscription under ss.3.03(b)(1), the Managing General Partner may subscribe to up to 5% of the Units under the provisions of ss.3.03(a) and its subsections, and, subject to the limitations on voting rights set forth in ss.4.03(c)(3), to that extent shall be deemed a Participant in the Partnership for all purposes under this Agreement. 3.03(b)(3). EFFECT OF AND EVIDENCING SUBSCRIPTION. The Managing General Partner has executed a Managing General Partner Signature Page which: 11 (i) evidences the Managing General Partner's required subscription under ss.3.03(b)(1); and (ii) may be amended to reflect the amount of any optional subscription under ss.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 NUMBER OF UNITS. 3.03(c)(1). MAXIMUM NUMBER OF UNITS. The maximum number of Units may not exceed 12,500 Units, which is up to $125,000,000 of cash subscription proceeds excluding the subscription discounts permitted under ss.3.03(a)(1). Notwithstanding the foregoing, the maximum number of Units in all partnerships in Atlas America Public #14-2004 Program, in the aggregate, shall not exceed 12,500 Units which is up to $125,000,000 of cash subscription proceeds excluding the subscription discounts permitted under ss.3.03(a)(1). 3.03(c)(2). MINIMUM NUMBER OF UNITS. The minimum number of Units shall equal at least 200 Units, but in any event not less than that number of Units which provides the Partnership with cash subscription proceeds of $2,000,000, excluding the subscription discounts permitted under ss.3.03(a)(1). If at the Offering Termination Date the minimum number of Units has not been received and accepted, then all monies deposited by subscribers shall be promptly returned to them. They shall receive interest earned on their subscription proceeds from the date the monies were deposited in escrow through the date of refund. The partnership may break escrow and begin its drilling activities in the Managing General Partner's sole discretion on receipt of the minimum subscription proceeds. 3.03(d). ACCEPTANCE OF SUBSCRIPTIONS. 3.03(d)(1). DISCRETION BY THE MANAGING GENERAL PARTNER. Acceptance of subscriptions is discretionary with the Managing General Partner. The Managing General Partner may reject any subscription for any reason it deems appropriate. 3.03(d)(2). TIME PERIOD IN WHICH TO ACCEPT SUBSCRIPTIONS. Subscriptions shall be accepted or rejected by the Partnership within 30 days of their receipt. If a subscription is rejected, then all funds shall be returned to the subscriber promptly. 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 Subscription Agreements were accepted by the Partnership. 3.04. CAPITAL CONTRIBUTIONS OF THE MANAGING GENERAL PARTNER. 3.04(a). 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 under ss.3.03(b)(1)(i), of not less than 25% of all Capital Contributions to the Partnership; and (ii) maintain a minimum Capital Account balance equal to not less than 1% of total positive Capital Account balances for the Partnership. 3.04(b). ON LIQUIDATION THE MANAGING GENERAL PARTNER MUST CONTRIBUTE DEFICIT BALANCE IN ITS CAPITAL ACCOUNT. The Managing General Partner shall contribute to the Partnership any deficit balance in its Capital Account on the occurrence of either of the following events: 12 (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 the liquidation. 3.04(c). INTEREST FOR CONTRIBUTIONS. The interest of the Managing General Partner, as Managing General Partner and not as a Participant, in the capital and revenues of the Partnership is in consideration for, and is the only consideration for, its required Capital Contributions to the Partnership. 3.05. PAYMENT OF SUBSCRIPTIONS. 3.05(a). MANAGING GENERAL PARTNER'S SUBSCRIPTIONS. The Managing General Partner shall pay any optional subscription under ss.3.03(b)(2) as set forth in ss.3.05(b)(1). 3.05(b). PARTICIPANT SUBSCRIPTIONS AND ADDITIONAL CAPITAL CONTRIBUTIONS OF THE INVESTOR GENERAL PARTNERS. 3.05(b)(1). PAYMENT OF SUBSCRIPTION AGREEMENTS. A Participant shall pay the amount designated as the subscription price on the Subscription Agreement executed by the Participant 100% in cash at the time of subscribing. A Participant shall receive interest on the amount he pays from the time his subscription proceeds are deposited in the escrow account, or the Partnership account after the minimum number of Units have been received as provided in ss.3.06(b), up until the Offering Termination Date. 3.05(b)(2). ADDITIONAL REQUIRED CAPITAL CONTRIBUTIONS OF THE INVESTOR GENERAL PARTNERS. Investor General Partners must make Capital Contributions to the Partnership when called by the Managing General Partner, in addition to their 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 Units under ss.6.01(b). 3.05(b)(3). DEFAULT PROVISIONS. The failure of an Investor General Partner to timely make a required additional Capital Contribution under this section results in his personal liability to the other Investor General Partners for the amount in default. The remaining Investor General Partners, in proportion to their respective number of Units, must pay the defaulting Investor General Partner's share of Partnership liabilities and obligations. In that event, the remaining Investor General Partners: (i) shall have a first and preferred lien on the defaulting Investor General Partner's interest in the Partnership to secure payment of the amount in default plus interest at the legal rate; (ii) shall be entitled to receive 100% of the defaulting Investor General Partner's cash distributions, in proportion to their respective number of Units, until the amount in default is recovered in full plus interest at the legal rate; and (iii) may commence legal action to collect the amount due plus interest at the legal rate. 3.06. PARTNERSHIP FUNDS. 3.06(a). FIDUCIARY DUTY. The Managing General Partner has a fiduciary responsibility for the safekeeping and use of all funds and assets of the Partnership, whether or not in the Managing General Partner's possession or control. The Managing General Partner shall not employ, or permit another to employ, the funds and assets 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 ss.ss.4.01, 4.02, 4.03, 4.04, 4.05 and 4.06 of this Agreement. 13 3.06(b). SPECIAL ACCOUNT AFTER THE RECEIPT OF THE MINIMUM PARTNERSHIP SUBSCRIPTIONS. Following the receipt of the minimum number of Units and breaking escrow, the funds of the Partnership shall be held in a separate interest-bearing account maintained for the Partnership and shall not be commingled with funds of any other entity. 3.06(c). INVESTMENT. 3.06(c)(1). INVESTMENTS IN OTHER ENTITIES. Partnership funds 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 ss.3.06(c)(2); (iii) multi-tier arrangements meeting the requirements of ss.4.03(d)(15); (iv) investments involving less than 5% of the Partnership's subscription proceeds which are a necessary and incidental part of a property acquisition transaction; and (v) investments in entities established solely to limit the Partnership's liabilities associated with the ownership or operation of property or equipment, provided that duplicative fees and expenses shall be prohibited. 3.06(c)(2). PERMISSIBLE INVESTMENTS BEFORE INVESTMENT IN PARTNERSHIP ACTIVITIES. After the Initial Closing Date and until proceeds from the offering are invested in the Partnership's operations, the proceeds may be temporarily invested in income producing short-term, highly liquid investments, in which there is appropriate safety of principal, such as U.S. Treasury Bills. ARTICLE IV CONDUCT OF OPERATIONS 4.01. ACQUISITION OF LEASES. 4.01(a). ASSIGNMENT TO PARTNERSHIP. 4.01(a)(1). IN GENERAL. The Managing General Partner shall select, acquire and assign or cause to have assigned to the Partnership full or partial interests in Leases, by any method customary in the natural gas and oil industry, subject to the terms and conditions set forth below. The Partnership and the other partnerships in Atlas America Public #14-2004 Program may acquire and develop interests in Leases covering one or more of the same Prospects, in the Managing General Partner's discretion. The Partnership shall acquire only Leases reasonably expected to meet the stated purposes of the Partnership. No Leases shall be acquired for the purpose of a subsequent sale, Farmout, or other disposition unless the acquisition is made after a well has been drilled to a depth sufficient to indicate that the acquisition would be in the Partnership's best interest. 4.01(a)(2). FEDERAL AND STATE LEASES. The Partnership is authorized to acquire Leases on federal and state lands. 4.01(a)(3). MANAGING GENERAL PARTNER'S DISCRETION AS TO TERMS AND BURDENS OF ACQUISITION. Subject to the provisions of ss.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) contributed to the Partnership by the Managing General Partner or its Affiliates; and 14 (ii) credited towards the Managing General Partner's required Capital Contribution set forth in ss.3.03(b)(1) at the Cost of the Lease, unless the Managing General Partner has cause to believe that Cost is materially more than the fair market value of the property, in which case the credit for the contribution must be made at a price not in excess of the fair market value. 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'S, OPERATOR'S OR THEIR AFFILIATES' RIGHTS IN THE REMAINDER INTERESTS. Subject to the provisions of ss.4.03(d) and its subsections, to the extent the Partnership does not acquire a full interest in a Lease from the Managing General Partner or its Affiliates, the remainder of the interest in the Lease may be held by the Managing General Partner or its Affiliates. They may either: (i) retain and exploit the remaining interest for their own account; or (ii) sell or otherwise dispose of all or a part of the remaining interest. Profits from the exploitation and/or disposition of their retained interests in the Leases shall be for the benefit of the Managing General Partner or its Affiliates to the exclusion of the Partnership. 4.01(a)(6). NO BREACH OF DUTY. Subject to the provisions of ss.4.03 and its subsections, acquisition of Leases from the Managing General Partner, the Operator or their Affiliates shall not be considered a breach of any obligation owed by them to the Partnership or the Participants. 4.01(b). NO OVERRIDING ROYALTY INTERESTS. Neither the Managing General Partner, the Operator nor any Affiliate shall retain any Overriding Royalty Interest on the Leases acquired by the Partnership. 4.01(c). TITLE AND NOMINEE ARRANGEMENTS. 4.01(c)(1). LEGAL TITLE. Legal title to all Leases acquired by the Partnership shall be held on a permanent basis in the name of the Partnership. However, Partnership properties may be held temporarily in the name of: (i) the Managing General Partner; (ii) the Operator; (iii) their Affiliates; or (iv) in the name of any nominee designated by the Managing General Partner to facilitate the acquisition of the properties. 4.01(c)(2). MANAGING GENERAL PARTNER'S DISCRETION. The Managing General Partner shall take the steps which are necessary in its best judgment to render title to the Leases to be acquired by the Partnership acceptable for the purposes of the Partnership. The Managing General Partner shall be free, however, to use its own best judgment in waiving title requirements. The Managing General Partner shall not be liable to the Partnership or to the other parties for any mistakes of judgment; nor shall the Managing General Partner be deemed to be making any warranties or representations, express or implied, as to the validity or merchantability of the title to the Leases assigned to the Partnership or the extent of the interest covered thereby except as otherwise provided in the Drilling and Operating Agreement. 4.01(c)(3). COMMENCEMENT OF OPERATIONS. The Partnership shall not begin operations on the Leases acquired by the Partnership unless the Managing General Partner is satisfied that necessary title requirements have been satisfied. 15 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 ss.4.03 and its subsections, and to any authority which may be granted the Operator under ss.4.02(c)(3)(b), the Managing General Partner shall have full authority to do all things deemed necessary or desirable by it in the conduct of the business of the Partnership. Without limiting the generality of the foregoing, the Managing General Partner is expressly authorized to engage in: (i) the making of all determinations of which Leases, wells and operations will be participated in by the Partnership, which includes: (a) which Leases are developed; (b) which Leases are abandoned; or (c) which leases are sold or assigned to other parties, including other investor ventures organized by the Managing General Partner, the Operator, or any of their Affiliates; (ii) the negotiation and execution on any terms deemed desirable in its sole discretion of any contracts, conveyances, or other instruments, considered useful to the conduct of the operations or the implementation of the powers granted it under this Agreement, including, without limitation: (a) the making of agreements for the conduct of operations, including agreements and financial instruments relating to hedging the Partnership's natural gas and oil; (b) the exercise of any options, elections, or decisions under any such agreements; and (c) the furnishing of equipment, facilities, supplies and material, services, and personnel; (iii) the exercise, on behalf of the Partnership or the parties, as the Managing General Partner in its sole judgment deems best, of all rights, elections and options granted or imposed by any agreement, statute, rule, regulation, or order; (iv) the making of all decisions concerning the desirability of payment, and the payment or supervision of the payment, of all delay rentals and shut-in and minimum or advance royalty payments; (v) the selection of full or part-time employees and outside consultants and contractors and the determination of their compensation and other terms of employment or hiring; (vi) the maintenance of insurance for the benefit of the Partnership and the parties as it deems necessary, but in no event less in amount or type than the following: (a) worker's compensation insurance in full compliance with the laws of the Commonwealth of Pennsylvania and any other applicable state laws; (b) liability insurance, including automobile, which has a $1,000,000 combined single limit for bodily injury and property damage in any one accident or occurrence and in the aggregate; and (c) liability and excess liability insurance as to bodily injury and property damage with combined limits of $50,000,000 during drilling operations and thereafter, per occurrence or accident and in the aggregate, which includes $1,000,000 of seepage, pollution and contamination insurance which protects and defends the insured against property damage or bodily injury claims from third-parties, other than a co-owner of the Working Interest, alleging seepage, pollution or contamination damage resulting from a pollution incident. The excess liability insurance shall be in place and effective no later than the date drilling operations begin, and the Partnership shall have the benefit of the Managing General Partner's $50,000,000 liability insurance on the same basis as the Managing General Partner and its Affiliates, including the Managing General Partner's other Programs; 16 (vii) the use of the funds and revenues of the Partnership, and the borrowing on behalf of, and the loan of money to, the Partnership, on any terms it sees fit, for any purpose, including without limitation: (a) the conduct or financing, in whole or in part, of the drilling and other activities of the Partnership; (b) the conduct of additional operations; and (c) the repayment of any borrowings or loans used initially to finance these operations or activities; (viii) the disposition, hypothecation, sale, exchange, release, surrender, reassignment or abandonment of any or all assets of the Partnership, including without limitation, the Leases, wells, equipment and production therefrom, provided that the sale of all or substantially all of the assets of the Partnership shall only be made as provided in ss.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 or on a Prospect which includes any part of the Leases; (xii) the exercise of the rights granted to it under the power of attorney created under this Agreement; and (xiii) the incurring of all costs and the making of all expenditures in any way related to any of the foregoing. 4.02(c)(2). SCOPE OF POWERS. The Managing General Partner's powers shall extend to any operation participated in by the Partnership or affecting its Leases, or other property or assets, irrespective of whether or not the Managing General Partner is designated operator of the operation by any outside persons participating therein. 4.02(c)(3). DELEGATION OF AUTHORITY. 4.02(c)(3)(a). IN GENERAL. The Managing General Partner may subcontract and delegate all or any part of its duties under this Agreement to any entity chosen by it, including an entity 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. 17 In no event shall any consideration received for operator services be in excess of competitive rates or duplicative of any consideration or reimbursements received under this Agreement. The Managing General Partner may not benefit by interpositioning itself between the Partnership and the actual provider of operator services. 4.02(c)(4). RELATED PARTY TRANSACTIONS. Subject to the provisions of ss.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 ss.4.02(c) and its subsections or elsewhere in this Agreement, the Managing General Partner, when specified, shall have the following additional express powers. 4.02(d)(1). DRILLING CONTRACTS. All Partnership Wells shall be drilled under the Drilling and Operating Agreement on a Cost plus 15% basis. The Managing General Partner or its Affiliates, as drilling contractor, may not do the following: (i) receive a rate that is not competitive with the rates charged by unaffiliated contractors in the same geographic region; (ii) enter into a turnkey drilling contract with the Partnership; (iii) profit by drilling in contravention of its fiduciary obligations to the Partnership; or (iv) benefit by interpositioning itself between the Partnership and the actual provider of drilling contractor services. 4.02(d)(2). POWER OF ATTORNEY. 4.02(d)(2)(a). IN GENERAL. Each Participant appoints the Managing General Partner his true and lawful attorney-in-fact for him and in his name, place, and stead and for his use and benefit, from time to time: (i) to create, prepare, complete, execute, file, swear to, deliver, endorse, and record any and all documents, certificates, government reports, or other instruments as may be required by law, or 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 Participant authorizes the attorney-in-fact to take any further action which the attorney-in-fact considers necessary or advisable in connection with any of the foregoing powers and rights granted to the Managing General Partner under this section and its subsections. Each party acknowledges that the power of attorney granted under subsection 4.02(d)(2)(a): (i) is a special power of attorney coupled with an interest and irrevocable; and (ii) shall survive the assignment by the Participant of the whole or a portion of his Units; except when the assignment is of all of the Participant's Units and the purchaser, transferee, or assignee of the Units is admitted as a successor Participant, the power of attorney shall survive the delivery of the assignment for the sole purpose of enabling the attorney-in-fact to execute, acknowledge, and file any agreement, certificate, instrument or document necessary to effect the substitution. 4.02(d)(2)(c). POWER OF ATTORNEY TO OPERATOR. The Managing General Partner is hereby authorized to grant a Power of Attorney to the Operator on behalf of the Partnership. 18 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 under ss.4.03(d)(8)(b), although they are not obligated to advance the funds to the Partnership. 4.02(e)(1)(b). LIMITATION ON BORROWING. 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's subscription proceeds. 4.02(f). TAX MATTERS PARTNER. 4.02(f)(1). DESIGNATION OF TAX MATTERS PARTNER. The Managing General Partner is hereby designated the Tax Matters Partner of the Partnership under Section 6231(a)(7) of the Code. The Managing General Partner is authorized to act in this capacity on behalf of the Partnership and the Participants and to take any action, including settlement or litigation, which it in its sole discretion deems to be in the best interest of the Partnership. 4.02(f)(2). COSTS INCURRED BY TAX MATTERS PARTNER. Costs incurred by the Tax Matters Partner shall be considered a Direct Cost of the Partnership. 4.02(f)(3). NOTICE TO PARTICIPANTS OF IRS PROCEEDINGS. The Tax Matters Partner shall notify all Participants of any partnership administrative or other legal proceedings involving the IRS, 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 that term is defined in Section 6231(a)(3) of Code, of the Partnership; (ii) he will not form or become and exercise any rights as a member of a group of Partners having a 5% or greater interest in the profits of the Partnership under Section 6223(b)(2) of the Code; and (iii) the Managing General Partner is authorized to file a copy of this Agreement, or pertinent portions of this Agreement, with the IRS under Section 6224(b) of the Code if necessary to perfect the waiver of rights under this subsection. 4.03. GENERAL RIGHTS AND OBLIGATIONS OF THE PARTICIPANTS AND RESTRICTED AND PROHIBITED TRANSACTIONS. 4.03(a)(1). LIMITED LIABILITY OF LIMITED PARTNERS. Limited Partners shall not be bound by the obligations of the Partnership other than as provided under the Delaware Revised Uniform Limited Partnership Act. Limited Partners shall not be personally liable for any debts of the Partnership or any of the obligations or losses of the Partnership beyond the amount of the subscription price designated on the Subscription Agreement executed by each respective Limited Partner unless: 19 (i) they also subscribe to the Partnership as Investor General Partners; or (ii) in the case of the Managing General Partner, it purchases Limited Partner Units. 4.03(a)(2). NO MANAGEMENT AUTHORITY OF PARTICIPANTS. Participants, other than the Managing General Partner if it buys Units, shall have no power over the conduct of the affairs of the Partnership. No Participant, other than the Managing General Partner if it buys Units, shall take part in the management of the business of the Partnership, or have the power to sign for or to bind the Partnership. 4.03(b). REPORTS AND DISCLOSURES. 4.03(b)(1). ANNUAL REPORTS AND FINANCIAL STATEMENTS. Beginning with the calendar year in which the Partnership had its Offering Termination Date, the Partnership shall provide each Participant an annual report within 120 days after the close of that calendar year, and beginning with the following calendar year, a report within 75 days after the end of the first six months of its calendar year, containing except as otherwise indicated, at least the information set forth below: (i) Audited financial statements of the Partnership, including a balance sheet and statements of income, cash flow, and Partners' equity, which shall be prepared on an accrual basis in accordance with generally accepted accounting principles with a reconciliation with respect to information furnished for income tax purposes and accompanied by an auditor's report containing an opinion of an independent public accountant selected by the Managing General Partner stating that his audit was made in accordance with generally accepted auditing standards and that in his opinion the financial statements present fairly the financial position, results of operations, partners' equity, and cash flows in accordance with generally accepted accounting principles. Semiannual reports are not required to be audited. (ii) A summary itemization, by type and/or classification of the total fees and compensation including any 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. Also, the independent certified public accountant shall provide written attestation annually, which will be included in the annual report, that the method used to make allocations was consistent with the method described in ss.4.04(a)(2)(c) of this Agreement and that the total amount of costs allocated did not materially exceed the amounts actually incurred by the Managing General Partner. If the Managing General Partner subsequently decides to allocate expenses in a manner different from that described in ss.4.04(a)(2)(c) of this Agreement, then the change must be reported to the Participants together with an explanation of the reason for the change and the basis used for determining the reasonableness of the new allocation method. (iii) A description of each Prospect in which the Partnership owns an interest, including: (a) the cost, location, and number of acres under Lease; and (b) the Working Interest owned in the Prospect by the Partnership. Succeeding reports, however, must only contain material changes, if any, regarding the Prospects. (iv) A list of the wells drilled or abandoned by the Partnership during the period of the report, indicating: (a) whether each of the wells has or has not been completed; (b) a statement of the cost of each well completed or abandoned; and (c) justification for wells abandoned after production has begun. 20 (v) A description of all Farmouts, farmins, and joint ventures, made during the period of the report, including: (a) the Managing General Partner's justification for the arrangement; and (b) a description of the material terms. (vi) A schedule reflecting: (a) the total Partnership costs; (b) the costs paid by the Managing General Partner and the costs paid by the Participants; (c) the total Partnership revenues; (d) the revenues received or credited to the Managing General Partner and the revenues received and credited to the Participants; and (e) a reconciliation of the expenses and revenues in accordance with the provisions of Article V. Additionally, on request the Managing General Partner will provide the information specified by Form 10-Q (if such report is required to be filed with the SEC) within 45 days after the close of each quarterly fiscal period. 4.03(b)(2). TAX INFORMATION. The Partnership shall, by March 15 of each year, prepare, or supervise the preparation of, and transmit to each Participant the information needed for the Participant to file the following: (i) his federal income tax return; (ii) any required state income tax return; and (iii) any other reporting or filing requirements imposed by any governmental agency or authority. 4.03(b)(3). RESERVE REPORT. Beginning with the second calendar year after the Offering Termination Date and every year thereafter, the Partnership shall provide to each Participant the following: (i) a summary of the computation of the Partnership's total oil and gas Proved Reserves; (ii) a summary of the computation of the present worth of the reserves determined using: (a) a discount rate of 10%; (b) a constant price for the oil; and (c) basing the price of gas on 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 that leads to the reduction of the Partnership's Proved Reserves of 10% or more, excluding: (i) reduction as a result of normal production; (ii) sales of reserves; or 21 (iii) 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 in this ss.4.03(b) shall be paid by the Partnership as Direct Costs. 4.03(b)(5). PARTICIPANT ACCESS TO RECORDS. The Participants and/or their representatives shall be permitted access to all Partnership records. The Participant may inspect and copy any of the records after giving adequate notice to the Managing General Partner at any reasonable time. Notwithstanding the foregoing, the Managing General Partner may keep logs, well reports, and other drilling and operating data confidential for reasonable periods of time. The Managing General Partner may release information concerning the operations of the Partnership to the sources that are customary in the industry or required by rule, regulation, or order of any regulatory body. 4.03(b)(6). REQUIRED LENGTH OF TIME TO HOLD RECORDS. The Managing General Partner must maintain and preserve during the term of the Partnership and for six years thereafter all accounts, books and other relevant documents which include: (i) a record that a Participant meets the suitability standards established in connection with an investment in the Partnership; and (ii) any appraisal of the fair market value of the Leases as set forth in ss.4.01(a)(4) or fair market value of any producing property as set forth in ss.4.03(d)(3). 4.03(b)(7). PARTICIPANT LISTS. The following provisions apply regarding access to the list of Participants: (i) an alphabetical list of the names, addresses, and business telephone numbers of the Participants along with the number of Units held by each of them (the "Participant List") must be maintained as a part of the Partnership's books and records and be available for inspection by any Participant or his designated agent at the home office of the Partnership on the Participant's request; (ii) the Participant List must be updated at least quarterly to reflect changes in the information contained in the Participant List; (iii) a copy of the Participant List must be mailed to any Participant requesting the Participant List within 10 days of the written request, printed in alphabetical order on white paper, and in a readily readable type size in no event smaller than 10-point type and a reasonable charge for copy work will be charged by the Partnership; (iv) the purposes for which a Participant may request a copy of the Participant List include, without limitation, matters relating to Participant's voting rights under this Agreement and the exercise of Participant's rights under the federal proxy laws; and (v) if the Managing General Partner neglects or refuses to exhibit, produce, or mail a copy of the Participant List as requested, the Managing General Partner shall be liable to any Participant requesting the list for the costs, including attorneys fees, incurred by that Participant for compelling the production of the Participant List, and for actual damages suffered by any Participant by reason of the refusal or neglect. It shall be a defense that the actual purpose and reason for the request for inspection or for a copy of the Participant List is to secure the list of Participants or other information for the purpose of selling the list or information or copies of the list, or of using the same for a commercial purpose other than in the interest of the applicant as a Participant relative to the affairs of the Partnership. The Managing General Partner will require the Participant requesting the Participant List to represent in writing that the list was not requested for a commercial purpose unrelated to the Participant's interest in the Partnership. The remedies provided under this subsection to Participants requesting copies of the Participant List are in addition to, and shall not in any way limit, other remedies available to Participants under federal law or the laws of any state. 22 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 ss.4.03(b) with: (i) the California Commissioner of Corporations; (ii) the Arizona Corporation Commission; and (iii) the securities commissions of other states which request the report. 4.03(c). MEETINGS OF PARTICIPANTS. 4.03(c)(1). PROCEDURE FOR A PARTICIPANT MEETING. 4.03(c)(1)(a). MEETINGS MAY BE CALLED BY MANAGING GENERAL PARTNER OR PARTICIPANTS. Meetings of the Participants may be called as follows: (i) by the Managing General Partner; or (ii) by Participants whose Units equal 10% or more of the total Units for any matters for which Participants may vote. The call for a meeting by Participants shall be deemed to have been made on receipt by the Managing General Partner of a written request from holders of the requisite percentage of Units stating the purpose(s) of the meeting. 4.03(c)(1)(b). NOTICE REQUIREMENT. The Managing General Partner shall deposit in the United States mail within 15 days after the receipt of the request, written notice to all Participants of the meeting and the purpose of the meeting. The meeting shall be held on a date not less than 30 days nor more than 60 days after the date of the mailing of the notice, at a reasonable time and place. Notwithstanding the foregoing, the date for notice of the meeting may be extended for a period of up to 60 days if, in the opinion of the Managing General Partner, the additional time is necessary to permit preparation of proxy or information statements or other documents required to be delivered in connection with the meeting by the SEC or other regulatory authorities. 4.03(c)(1)(c). MAY VOTE BY PROXY. Participants shall have the right to vote at any Participant meeting either: (i) in person; or (ii) by proxy. 4.03(c)(2). SPECIAL VOTING RIGHTS. At the request of Participants whose Units equal 10% or more of the total Units, the Managing General Partner shall call for a vote by Participants. Each Unit is entitled to one vote on all matters, and each fractional Unit is entitled to that fraction of one vote equal to the fractional interest in the Unit. Participants whose Units equal a majority of the total Units may, without the concurrence of the Managing General Partner or its Affiliates, vote to: (i) dissolve the Partnership; (ii) remove the Managing General Partner and elect a new Managing General Partner; (iii) elect a new Managing General Partner if the Managing General Partner elects to withdraw from the Partnership; (iv) remove the Operator and elect a new Operator; (v) approve or disapprove the sale of all or substantially all of the assets of the Partnership; 23 (vi) cancel any contract for services with the Managing General Partner, the Operator, or their Affiliates without penalty on 60 days notice; and (vii) amend this Agreement; provided however: (a) any amendment may not increase the duties or liabilities of any Participant or the Managing General Partner or increase or decrease the profit or loss sharing or required Capital Contribution of any Participant or the Managing General Partner without the approval of the Participant or the Managing General Partner; 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 ss.4.03(c)(2)(ii) and (iv) above; or (ii) any transaction between the Partnership and the Managing General Partner or its Affiliates. In determining the requisite percentage in interest of Units necessary to approve any Partnership matter on which the Managing General Partner and its Affiliates may not vote or consent, any Units owned by the Managing General Partner and its Affiliates shall not be included. 4.03(c)(4). RESTRICTIONS ON LIMITED PARTNER VOTING RIGHTS. The exercise by the Limited Partners of the rights granted Participants under ss.4.03(c), except for the special voting rights granted Participants under ss.4.03(c)(2), shall be subject to the prior legal determination that the grant or exercise of the powers will not adversely affect the limited liability of Limited Partners. Notwithstanding the foregoing, if in the opinion of counsel to the Partnership the legal determination is not necessary under Delaware law to maintain the limited liability of the Limited Partners, then it shall not be required. A legal determination under this paragraph may be made either pursuant to: (i) an opinion of counsel, the counsel being independent of the Partnership and selected on the vote of Limited Partners whose Units equal a majority of the total Units held by Limited Partners; or (ii) a declaratory judgment issued by a court of competent jurisdiction. The Investor General Partners may exercise the rights granted to the Participants whether or not the Limited Partners can participate in the vote if the Investor General Partners represent the requisite percentage of Units necessary to take the action. 4.03(d). TRANSACTIONS WITH THE MANAGING GENERAL PARTNER. 4.03(d)(1). TRANSFER OF EQUAL PROPORTIONATE INTEREST. When the Managing General Partner or an Affiliate (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) sells, transfers or conveys any natural gas, oil or other mineral interests or property to the Partnership, it must, at the same time, sell, transfer or convey to the Partnership an equal proportionate interest in all its other property in the same Prospect. Notwithstanding, a Prospect shall be deemed to consist of the drilling or spacing unit on which the well will be drilled by the Partnership, which is the minimum area permitted by state law or local practice on which one well may be drilled, if the following two conditions are met: (i) the geological feature to which the well will be drilled contains Proved Reserves; and (ii) the drilling or spacing unit protects against drainage. 24 With respect to a natural gas or oil 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 and/or 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. Additionally, for a period of five years after the drilling of the Partnership Well neither the Managing General Partner nor its Affiliates may drill any well: (i) 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 (ii) in the Mississippian/Upper Devonian Sandstone reservoirs in Fayette County and Greene County, Pennsylvania within at least 1,000 feet from a producing well, although a partnership may drill a new well or re-enter an existing well which is closer than 1,000 feet to a plugged and abandoned 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 in which the Managing General Partner or an Affiliate (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) owns a separate property interest and the activities of the Partnership were material in establishing the existence of Proved Undeveloped Reserves that are attributable to the separate property interest, then the separate property interest or a portion thereof must be sold, transferred, or conveyed to the Partnership as set forth in this section and ss.ss.4.01(a)(4) and 4.03(d)(2). Notwithstanding the foregoing, Prospects in the Clinton/Medina geological formation, the Mississippian and/or Upper Devonian Sandstone reservoirs, or any other formation or reservoir shall not be enlarged or contracted if the Prospect was limited to the drilling or spacing unit because the well was being drilled to Proved Reserves in the geological formation and the drilling or spacing unit protected against drainage. 4.03(d)(2). TRANSFER OF LESS THAN THE MANAGING GENERAL PARTNER'S AND ITS AFFILIATES' ENTIRE INTEREST. A sale, transfer or a conveyance to the Partnership of less than all of the ownership of the Managing General Partner or an Affiliate (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) in any Prospect shall not be made unless: (i) the interest retained by the Managing General Partner or the Affiliate is a proportionate Working Interest; (ii) the respective obligations of the Managing General Partner or its Affiliates and the Partnership are substantially the same after the sale of the interest by the Managing General Partner or its Affiliates; and (iii) the Managing General Partner's interest in revenues does not exceed the amount proportionate to its retained Working Interest. This section does not prevent the Managing General Partner or its Affiliates from subsequently dealing with their retained interest as they may choose with unaffiliated parties or Affiliated partnerships. 4.03(d)(3). LIMITATIONS ON SALE OF UNDEVELOPED AND DEVELOPED LEASES TO THE MANAGING GENERAL PARTNER. Other than another Program managed by the Managing General Partner and its Affiliates as set forth in ss.ss.4.03(d)(5) and 4.03(d)(9), the Managing General Partner and its Affiliates shall not receive a Farmout or purchase any undeveloped Leases from the Partnership other than at the higher of Cost or fair market value. The Managing General Partner and its Affiliates, other than an Affiliated Income Program, may not purchase any producing natural gas or oil property from the Partnership unless: (i) the sale is in connection with the liquidation of the Partnership; or (ii) the Managing General Partner's well supervision fees under the Drilling and Operating Agreement for the well have exceeded the net revenues of the well, determined without regard to the Managing General Partner's well supervision fees for the well, for a period of at least three consecutive months. 25 In both (i) and (ii), the sale must be at fair market value supported by an appraisal of an Independent Expert selected by the Managing General Partner. 4.03(d)(4). LIMITATIONS ON ACTIVITIES OF THE MANAGING GENERAL PARTNER AND ITS AFFILIATES ON LEASES ACQUIRED BY THE PARTNERSHIP. During a period of five years after the Offering Termination Date of the Partnership, if the Managing General Partner or any of its Affiliates (excluding another Program in which the interest of the Managing General Partner or its Affiliates is substantially similar to or less than their interest in the Partnership) proposes to acquire an interest from an unaffiliated person in a Prospect in which the Partnership possesses an interest or in a Prospect in which the Partnership's interest has been terminated without compensation within one year preceding the proposed acquisition, then the following conditions shall apply: (i) 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 transfer of an undeveloped Lease from the Partnership to an Affiliated Drilling Program must be made at fair market value if the undeveloped Lease has been held for more than two years. Otherwise, if the Managing General Partner deems it to be in the best interest of the Partnership, the transfer may be made at Cost. An Affiliated Income Program may purchase a producing natural gas and oil property from the Partnership at any time at: (i) fair market value as supported by an appraisal from an Independent Expert if the property has been held by the Partnership for more than six months or significant expenditures have been made in connection with the property; or (ii) Cost as adjusted for intervening operations if the Managing General Partner deems it to be in the best interest of the Partnership. However, these prohibitions shall not apply to joint ventures or Farmouts among Affiliated partnerships, provided that: (i) the respective obligations and revenue sharing of all parties to the transaction are substantially the same; and (ii) the compensation arrangement or any other interest or right of either the Managing General Partner or its Affiliates is the same in each Affiliated partnership or if different, the aggregate compensation of the Managing General Partner or the Affiliate is reduced to reflect the lower compensation arrangement. 4.03(d)(6). SALE OF ALL ASSETS. The sale of all or substantially all of the assets of the Partnership, including without limitation, Leases, wells, equipment and production therefrom, shall be made only with the consent of Participants whose Units equal a majority of the total Units. 4.03(d)(7). SERVICES. 4.03(d)(7)(a). COMPETITIVE RATES. The Managing General Partner and any Affiliate shall not render to the Partnership any oil field, equipage, or other services nor sell or lease to the Partnership any equipment or related supplies unless: 26 (i) the person is engaged, independently of the Partnership and as an ordinary and ongoing business, in the business of rendering the services or selling or leasing the equipment and supplies to a substantial extent to other persons in the natural gas and oil industry in addition to the partnerships in which the Managing General Partner or an Affiliate has an interest; and (ii) the compensation, price, or rental therefor is competitive with the compensation, price, or rental of other persons in the area engaged in the business of rendering comparable services or selling or leasing comparable equipment and supplies which could reasonably be made available to the Partnership. If the person is not engaged in such a business, then the compensation, price or rental shall be the Cost of the services, equipment or supplies to the person or the competitive rate which could be obtained in the area, whichever is less. 4.03(d)(7)(b). IF NOT DISCLOSED IN THE PROSPECTUS OR THIS AGREEMENT THEN SERVICES BY THE MANAGING GENERAL PARTNER MUST BE DESCRIBED IN A SEPARATE CONTRACT AND CANCELABLE. Any services for which the Managing General Partner or an Affiliate is to receive compensation other than those described in this Agreement or the Prospectus shall be set forth in a written contract which precisely describes the services to be rendered and all compensation to be paid. These contracts are cancelable without penalty on 60 days written notice by Participants whose Units equal a majority of the total Units. 4.03(d)(8). LOANS. 4.03(d)(8)(a). NO LOANS FROM THE PARTNERSHIP. No loans or advances shall be made by the Partnership to the Managing General Partner or 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). FARMOUTS. The Managing General Partner shall not enter into a Farmout to avoid its paying its share of costs related to drilling an undeveloped Lease. The Partnership shall not Farmout an undeveloped Lease or well activity to the Managing General Partner or its Affiliates except as set forth in ss.4.03(d)(3). Notwithstanding, this restriction shall not apply to Farmouts between the Partnership and another partnership managed by the Managing General Partner or its Affiliates, either separately or jointly, provided that the respective obligations and revenue sharing of all parties to the transactions are substantially the same and the compensation arrangement or any other interest or right of the Managing General Partner or its Affiliates is the same in each partnership, or, if different, the aggregate compensation of the Managing General Partner and its Affiliates is reduced to reflect the lower compensation agreement. The Partnership may Farmout an undeveloped lease or well activity only if the Managing General Partner, exercising the standard of a prudent operator, determines that: (i) the Partnership lacks the funds to complete the oil and gas operations on the Lease or well and cannot obtain suitable financing; (ii) drilling on the Lease or the intended well activity would concentrate excessive funds in one location, creating undue risks to the Partnership; (iii) the Leases or well activity have been downgraded by events occurring after assignment to the Partnership so that development of the Leases or well activity would not be desirable; or 27 (iv) the best interests of the Partnership would be served. If the Partnership Farmouts a Lease or well activity, the Managing General Partner must retain on behalf of the Partnership the economic interests and concessions as a reasonably prudent oil and gas operator would or could retain under the circumstances prevailing at the time, consistent with industry practices. 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 ss.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 natural gas and oil will be sold and to whom and at what price the natural gas and oil of other natural gas and oil Programs which the Managing General Partner has sponsored or will sponsor will be sold. For example, each seller of natural gas and oil in a given area will be paid a weighted average selling price for all natural gas and oil sold in that geographic area. The Managing General Partner, in its sole discretion, shall determine what constitutes a 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 Costs, the Managing General Partner's compensation, Partnership expenses or other fees and costs; (ii) there shall be no substantive alteration in the fiduciary and contractual relationship between the Managing General Partner and the Participants; and (iii) there shall be no diminishment in the voting rights of the Participants. 4.03(d)(16). ROLL-UP LIMITATIONS. 4.03(d)(16)(a). REQUIREMENT FOR APPRAISAL AND ITS ASSUMPTIONS. In connection with a proposed Roll-Up, an appraisal of all Partnership assets shall be obtained from a competent Independent Expert. If the appraisal will be included in a prospectus used to offer securities of a Roll-Up Entity, then the appraisal shall be filed with the SEC and the Administrator as an exhibit to the registration statement for the offering. Thus, an issuer using the appraisal shall be subject to liability for violation of Section 11 of the Securities Act of 1933 and comparable provisions under state law for any material misrepresentations or material omissions in the appraisal. Partnership assets shall be appraised on a consistent basis. The appraisal shall be based on all relevant information, including current reserve estimates prepared 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. 28 The terms of the engagement of the Independent Expert shall clearly state that the engagement is for the benefit of the Partnership and the Participants. A summary of the independent appraisal, indicating all material assumptions underlying the appraisal, shall be included in a report to the Participants in connection with a proposed Roll-Up. 4.03(d)(16)(b). RIGHTS OF PARTICIPANTS WHO VOTE AGAINST PROPOSAL. In connection with a proposed Roll-Up, Participants who vote "no" on the proposal shall be offered the choice of: (i) accepting the securities of the Roll-Up Entity offered in the proposed Roll-Up; or (ii) one of the following: (a) remaining as Participants in the Partnership and preserving their Units in the Partnership on the same terms and conditions as existed previously; or (b) receiving cash in an amount equal to the Participants' pro rata share of the appraised value of the net assets of the Partnership based on their respective number of Units. 4.03(d)(16)(c). NO ROLL-UP IF DIMINISHMENT OF VOTING RIGHTS. The Partnership shall not participate in any proposed Roll-Up which, if approved, would result in the diminishment of any Participant's voting rights under the Roll-Up Entity's chartering agreement. In no event shall the democracy rights of Participants in the Roll-Up Entity be less than those provided for under ss.ss.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 that would operate to materially impede or frustrate the accumulation of shares by any purchaser of the securities of the Roll-Up Entity, except to the minimum extent necessary to preserve the tax status of the Roll-Up Entity. The Partnership shall not participate in any proposed Roll-Up transaction which would limit the ability of a Participant to exercise the voting rights of its securities of the Roll-Up Entity on the basis of the number of Units held by that Participant. 4.03(d)(16)(e). NO ROLL-UP IF ACCESS TO RECORDS WOULD BE LIMITED. The Partnership shall not participate in a Roll-Up in which Participants' rights of access to the records of the Roll-Up Entity will be less than those provided for under ss.ss.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 Units equal 66% of the total Units do not vote to approve the proposed Roll-Up. 4.03(d)(16)(g). ROLL-UP APPROVAL. The Partnership shall not participate in a Roll-Up transaction unless the Roll-Up transaction is approved by Participants whose Units equal 66% of the total Units. 4.03(d)(17). DISCLOSURE OF BINDING AGREEMENTS. Any agreement or arrangement which binds the Partnership must be disclosed in the Prospectus. 4.03(d)(18). TRANSACTIONS MUST BE FAIR AND REASONABLE. Neither the Managing General Partner nor any Affiliate shall sell, transfer, or convey any property to or purchase any property from the Partnership, directly or indirectly, except under transactions that are fair and reasonable, nor take any action with respect to the assets or property of the Partnership which does not primarily benefit the Partnership. 4.04. DESIGNATION, COMPENSATION AND REMOVAL OF MANAGING GENERAL PARTNER AND REMOVAL OF OPERATOR. 4.04(a). MANAGING GENERAL PARTNER. 4.04(a)(1). TERM OF SERVICE. Atlas shall serve as the Managing General Partner of the Partnership until either it: 29 (i) is removed pursuant to ss.4.04(a)(3); or (ii) withdraws pursuant to ss.4.04(a)(3)(f). 4.04(a)(2). COMPENSATION OF MANAGING GENERAL PARTNER. In addition to the compensation set forth in ss.ss.4.01(a)(4) and 4.02(d)(1), the Managing General Partner shall receive the compensation set forth in ss.ss.4.04(a)(2)(b) through 4.04(a)(2)(g). 4.04(a)(2)(a). CHARGES MUST BE NECESSARY AND REASONABLE. Charges by the Managing General Partner for goods and services must be fully supportable as to: (i) the necessity of the goods and services; and (ii) the reasonableness of the amount charged. All actual and necessary expenses incurred by the Partnership may be paid out of the Partnership's subscription proceeds and revenues. 4.04(a)(2)(b). DIRECT COSTS. The Managing General Partner and its Affiliates shall be reimbursed for all Direct Costs. Direct Costs, however, shall be billed directly to and paid by the Partnership to the extent practicable. 4.04(a)(2)(c). ADMINISTRATIVE COSTS. The Managing General Partner shall receive 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. The Managing General Partner shall be responsible for gathering and transporting the natural gas produced by the Partnership to interstate pipeline systems, local distribution companies and/or end-users in the area and shall receive a gathering fee at a competitive rate for gathering and transporting the Partnership's gas. If the Partnership's gas production is gathered and transported through the gathering system owned by Atlas Pipeline Partners, then the Managing General Partner shall apply its gathering fee towards the agreement between Atlas Pipeline Partners and Atlas America, Inc., Resource Energy, Inc., and Viking Resources Corporation. If the Partnership's gas production is gathered and transferred through a gathering system owned by a third-party, then the Managing General Partner shall pay a portion or all of its gathering fee to the third-party gathering the natural gas. 4.04(a)(2)(e). DEALER-MANAGER FEE. Subject to ss.3.03(a)(1), the Dealer-Manager shall receive on each Unit sold to investors: (i) a 2.5% Dealer-Manager fee; (ii) a 7% Sales Commission; (iii) a .5% accountable Reimbursement for Permissible Non-Cash Compensation; and (iv) an up to .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. 30 4.04(a)(2)(g). OTHER TRANSACTIONS. The Managing General Partner and its Affiliates may enter into transactions pursuant to ss.4.03(d)(7) with the Partnership and shall be entitled to compensation under that section. 4.04(a)(3). REMOVAL OF MANAGING GENERAL PARTNER. 4.04(a)(3)(a). MAJORITY VOTE REQUIRED TO REMOVE THE MANAGING GENERAL PARTNER. The Managing General Partner may be removed at any time on 60 days' advance written notice to the outgoing Managing General Partner by the affirmative vote of Participants whose Units equal a majority of the total Units. If the Participants vote to remove the Managing General Partner from the Partnership, then Participants must elect by an affirmative vote of Participants whose Units equal a majority of the total Units either to: (i) terminate, dissolve, and wind up the Partnership; or (ii) continue as a successor limited partnership under all the terms of this Partnership Agreement as provided in ss.7.01(c). If the Participants elect to continue as a successor limited partnership, then the Managing General Partner shall not be removed until a substituted Managing General Partner has been selected by an affirmative vote of Participants whose Units equal a majority of the total Units and installed as such. 4.04(a)(3)(b). VALUATION OF MANAGING GENERAL PARTNER'S INTEREST IN THE PARTNERSHIP. If the Managing General Partner is removed, then its interest in the Partnership shall be determined by appraisal by a qualified Independent Expert. The Independent Expert shall be selected by mutual agreement between the removed Managing General Partner and the incoming Managing General Partner. The appraisal shall take into account an appropriate discount, to reflect the risk of recovery of natural gas and oil reserves, but not less than that used 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 in the Partnership as Managing General Partner and not as a Participant for the value determined by the Independent Expert. 4.04(a)(3)(d). METHOD OF PAYMENT. The method of payment for the removed Managing General Partner's interest must be fair and protect the solvency and liquidity of the Partnership. The method of payment shall be as follows: (i) when the termination is voluntary, the method of payment shall be a non-interest bearing unsecured promissory note with principal payable, if at all, from distributions which the Managing General Partner otherwise would have received under 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. Notwithstanding any other provision in this Agreement, the Partnership or the successor Managing General Partner shall not: (i) be a party to any natural gas supply agreement that the Managing General Partner or its Affiliates enters into with a third-party; 31 (ii) have any rights pursuant to such natural gas supply agreement; or (iii) receive any interest in the Managing General Partner's and its Affiliates' pipeline or gathering system or compression facilities. 4.04(a)(3)(f). THE MANAGING GENERAL PARTNER'S RIGHT TO VOLUNTARILY WITHDRAW. At any time beginning 10 years after the Offering Termination Date and the Partnership's primary drilling activities, the Managing General Partner may voluntarily withdraw as Managing General Partner on giving 120 days' written notice of withdrawal to the Participants. If the Managing General Partner withdraws, then the following conditions shall apply: (i) the Managing General Partner's interest in the Partnership shall be determined as described in ss.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 ss.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 under the conditions set forth in ss.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 a greater amount of Direct Costs or Administrative Costs is not allocated to the Participants. 4.04(a)(4). REMOVAL OF OPERATOR. The Operator may be removed and a new Operator may be substituted at any time on 60 days advance written notice to the outgoing Operator by the Managing General Partner acting on behalf of the Partnership on the affirmative vote of Participants whose Units equal a majority of the total Units. The Operator shall not be removed until a substituted Operator has been selected by an affirmative vote of Participants whose Units equal a majority of the total Units and installed as such. 4.05. INDEMNIFICATION AND EXONERATION. 4.05(a)(1). STANDARDS FOR THE MANAGING GENERAL PARTNER NOT INCURRING LIABILITY TO THE PARTNERSHIP OR PARTICIPANTS. The Managing General Partner, the Operator, and their Affiliates shall not have any liability whatsoever to the Partnership or to any Participant for any loss suffered by the Partnership or Participants which arises out of any action or inaction of the Managing General Partner, the Operator, or their Affiliates if: (i) the Managing General Partner, the Operator, and their Affiliates determined in good faith that the course of conduct was in the best interest of the Partnership; (ii) the Managing General Partner, the Operator, and their Affiliates were acting on behalf of, or performing services for, the Partnership; and (iii) the course of conduct did not constitute negligence or misconduct of the Managing General Partner, the Operator, or their Affiliates. 4.05(a)(2). STANDARDS FOR MANAGING GENERAL PARTNER INDEMNIFICATION. The Managing General Partner, the Operator, and their Affiliates shall be indemnified by the Partnership against any losses, judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by them in connection with the Partnership, provided that: 32 (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) tangible net assets; (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 SEC, the Massachusetts Securities Division, and any state securities regulatory authority in which plaintiffs claim they were offered or sold Units with respect to the issue of indemnification for violation of securities laws. 4.05(a)(4). STANDARDS FOR ADVANCEMENT OF FUNDS TO THE MANAGING GENERAL PARTNER AND INSURANCE. The advancement of Partnership funds to the Managing General Partner, the Operator, or their Affiliates for legal expenses and other costs incurred as a result of any legal action for which indemnification is being sought is permissible only if the Partnership has adequate funds available and the following conditions are satisfied: (i) the legal action relates to acts or omissions with respect to the performance of duties or services on behalf of the Partnership; (ii) the legal action is initiated by a third-party who is not a Participant, or the legal action is initiated by a Participant and a court of competent jurisdiction specifically approves the advancement; and (iii) the Managing General Partner or its Affiliates undertake to repay the advanced funds to the Partnership, together with the applicable legal rate of interest thereon, in cases in which such party is found not to be entitled to indemnification. The Partnership shall not bear the cost of that portion of insurance which insures the Managing General Partner, the Operator, or their Affiliates for any liability for which they could not be indemnified pursuant to ss.ss.4.05(a)(1) and 4.05(a)(2). 4.05(b). LIABILITY OF PARTNERS. Under the Delaware Revised Uniform Limited Partnership Act, the Investor General Partners are liable jointly and severally for all liabilities and obligations of the Partnership. Notwithstanding the foregoing, as among themselves, the Investor General Partners agree that each shall be solely and individually responsible only for his pro rata share of the liabilities and obligations of the Partnership based on his respective number of Units. 33 In addition, the Managing General Partner agrees to use its corporate assets to indemnify each of the Investor General Partners against all Partnership related liabilities which exceed the Investor General Partner's interest in the undistributed net assets of the Partnership and insurance proceeds, if any. Further, the Managing General Partner agrees to indemnify each Investor General Partner against any personal liability as a result of the unauthorized acts of another Investor General Partner. If the Managing General Partner provides indemnification, then each Investor General Partner who has been indemnified shall transfer and subrogate his rights for contribution from or against any other Investor General Partner to the Managing General Partner. 4.05(c). ORDER OF PAYMENT OF CLAIMS. Claims shall be paid as follows: (i) first, out of any insurance proceeds; (ii) second, out of Partnership assets and revenues; and (iii) last, by the Managing General Partner as provided in ss.ss.3.05(b)(2) and (3) and 4.05(b). No Limited Partner shall be required to reimburse the Managing General Partner, the Operator, their Affiliates, or the Investor General Partners for any liability in excess of his agreed Capital Contribution, except: (i) for a liability resulting from the Limited Partner's unauthorized participation in 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, the Managing General Partner, the Operator, or their Affiliates, which is authorized by this Agreement shall be deemed a breach of any obligation owed by the Managing General Partner, the Operator, or their Affiliates to the Partnership or the Participants. 4.06. OTHER ACTIVITIES. 4.06(a). THE MANAGING GENERAL PARTNER MAY PURSUE OTHER NATURAL GAS AND OIL ACTIVITIES FOR ITS OWN ACCOUNT. The Managing General Partner, the Operator, and their Affiliates are now engaged, and will engage in the future, for their own account and for the account of others, including other investors, in all aspects of the natural gas and oil business. This includes without limitation, the evaluation, acquisition, and sale of producing and nonproducing Leases, and the exploration for and production of natural gas, oil and other minerals. The Managing General Partner is required to devote only so much of its time 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: (i) continue their activities, or initiate further such activities, individually, jointly with others, or as a part of any other limited or general partnership, tax partnership, joint venture, or other entity or activity to which they are or may become a party, in any locale and in the same fields, areas of operation or prospects in which the Partnership may likewise be active; (ii) reserve partial interests in Leases being assigned to the Partnership or any other interests not expressly prohibited by this Agreement; (iii) deal with the Partnership as independent parties or through any other entity in which they may be interested; (iv) conduct business with the Partnership as set forth in this Agreement; and (v) participate in such other investor operations, as investors or otherwise. 34 The Managing General Partner and its Affiliates shall not be required to permit the Partnership or the Participants to participate in any of the operations in which the Managing General Partner and its Affiliates may be interested or share in any profits or other benefits from the operations. However, except as otherwise provided in this Agreement, the Managing General Partner and its Affiliates may pursue business opportunities that are consistent with the Partnership's investment objectives for their own account only after they have determined that the opportunity either: (i) cannot be pursued by the Partnership because of insufficient funds; or (ii) it is not appropriate for the Partnership under the existing circumstances. 4.06(b). MANAGING GENERAL PARTNER MAY MANAGE MULTIPLE PARTNERSHIPS. The Managing General Partner or its Affiliates may manage multiple Programs simultaneously. 4.06(c). PARTNERSHIP HAS NO INTEREST IN NATURAL GAS CONTRACTS OR PIPELINES AND GATHERING SYSTEMS. Notwithstanding any other provision in this Agreement, the Partnership shall not: (i) be a party to any natural gas supply agreement that the Managing General Partner, the Operator, or their Affiliates enter into with a third-party or have any rights pursuant to such natural gas supply agreement; or (ii) receive any interest in the Managing General Partner's, the Operator's, and their Affiliates' 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 and its subsections. 5.01(a). COSTS. Costs shall be charged as set forth below. 5.01(a)(1). ORGANIZATION AND OFFERING COSTS. Organization and Offering Costs shall be charged 100% to the Managing General Partner. For purposes of sharing in revenues under ss.5.01(b)(4), the Managing General Partner shall be credited with Organization and Offering Costs paid by it and for services provided by it as Organization Costs up to and including 15% of the Partnership's subscription proceeds. Any Organization and Offering Costs paid and/or provided in services by the Managing General Partner in excess of this amount shall not be credited towards the Managing General Partner's required Capital Contribution or revenue share set forth in ss.5.01(b)(4). The Managing General Partner's credit for services provided to the Partnership as Organization Costs shall be determined based on generally accepted accounting principles. 5.01(a)(2). INTANGIBLE DRILLING COSTS. Intangible Drilling Costs shall be charged 100% to the Participants. 5.01(a)(3). TANGIBLE COSTS. Tangible Costs shall be charged 66% to the Managing General Partner and 34% to the Participants. However, if the total Tangible Costs for all of the Partnership's wells that would be charged to the Participants exceeds an amount equal to 10% of the Partnership's subscription proceeds, then the excess shall be charged to the Managing General Partner. 5.01(a)(4). OPERATING COSTS, DIRECT COSTS, ADMINISTRATIVE COSTS AND ALL OTHER COSTS. Operating Costs, Direct Costs, Administrative Costs, and all other Partnership costs not specifically allocated shall be charged to the parties in the same ratio as the related production revenues are being credited. 5.01(a)(5). ALLOCATION OF INTANGIBLE DRILLING COSTS AND TANGIBLE COSTS AT PARTNERSHIP CLOSINGS. Intangible Drilling Costs and the Participants' share of Tangible Costs of a well or wells to be drilled and completed with the proceeds of a Partnership closing shall be charged 100% to the Participants who are admitted to the Partnership in that closing and shall not be reallocated to take into account other Partnership closings. 35 Although the proceeds of each Partnership closing will be used to pay the costs of drilling different wells, not less than 90% of each Participant's subscription proceeds shall be applied to Intangible Drilling Costs and not more than 10% of each Participant's subscription proceeds shall be applied to Tangible Costs regardless of when he subscribes. 5.01(a)(6). LEASE COSTS. The Leases shall be contributed to the Partnership by the Managing General Partner as set forth in ss.4.01(a)(4). 5.01(b). REVENUES. Revenues shall be credited as set forth below. 5.01(b)(1). ALLOCATION OF REVENUES ON DISPOSITION OF PROPERTY. If the parties' Capital Accounts are adjusted to reflect the simulated depletion of a natural gas or oil property of the Partnership, then the portion of the total amount realized by the Partnership on the taxable disposition of the property that represents recovery of its simulated tax basis in the property shall be allocated to the parties in the same proportion as the aggregate adjusted tax basis of the property was allocated to the parties or their predecessors in interest. If the parties' Capital Accounts are adjusted to reflect the actual depletion of a natural gas or oil property of the Partnership, then the portion of the total amount realized by the Partnership on the taxable disposition of the property that equals the parties' aggregate remaining adjusted tax basis in the property shall be allocated to the parties in proportion to their respective remaining adjusted tax bases in the property. Thereafter, any excess shall be allocated to the Managing General Partner in an amount equal to the difference between the fair market value of the Lease at the time it was contributed to the Partnership and its simulated or actual adjusted tax basis at that time. Finally, any excess shall be credited as provided in ss.5.01(b)(4), below. In the event of a sale of developed natural gas and oil properties with equipment on the properties, 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 each Participant's subscription proceeds before the Offering Termination Date under ss.3.05(b)(1) shall be credited to the accounts of the respective subscribers who paid the subscription proceeds to the Partnership. The interest shall be paid to the Participant not later than the Partnership's first cash distribution from operations. After the Offering Termination Date and until proceeds from the offering are invested in the Partnership's natural gas and oil operations, any interest income from temporary investments shall be allocated pro rata to the Participants providing the subscription proceeds. All other interest income, including interest earned on the deposit of production revenues, shall be credited as provided in ss.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 ss.5.01(b)(4)(a), the Managing General Partner and the Participants shall share in all other Partnership revenues in the same percentage as their respective Capital Contribution bears to the total Partnership Capital Contributions, except that the Managing General Partner shall receive an additional 7% of Partnership revenues. However, the Managing General Partner's total revenue share may not exceed 35% of Partnership revenues. 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 shall receive 32% of the Partnership revenues and the Participants shall receive 68% of the Partnership revenues. On the other hand, if the Managing General Partner contributes 30% of the total Partnership Capital Contributions and the Participants contribute 70% of the total Partnership Capital Contributions, then the Managing General Partner shall receive 35% of the Partnership revenues, not 37%, because its revenue share cannot exceed 35% of Partnership revenues, and the Participants shall receive 65% of Partnership revenues. 5.01(b)(4)(a). SUBORDINATION. The Managing General Partner shall subordinate up to 50% of its share of Partnership Net Production Revenues to the receipt by Participants of cash distributions from the Partnership equal to $1,000 per Unit (which is 10% per Unit) regardless of their actual subscription price of the Units, in each of the first five 12-month periods beginning with the Partnership's first cash distributions from operations. In this regard: 36 (i) the 60-month subordination period shall begin with the first cash distribution from operations to the Participants, but no subordination distributions to the Participants shall be required until the Partnership's first cash distribution to the Participants after substantially all Partnership wells have been drilled, completed, and placed in production in a sales line; (ii) subsequent subordination distributions, if any, shall be determined and made at the time of each subsequent distribution of revenues to the Participants; and (iii) the Managing General Partner shall not subordinate more than 50% of its share of Partnership Net Production Revenues in any subordination 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) $1,000 per Unit (10% per Unit) in the first 12-month period; (b) $2,000 per Unit (20% per Unit) in the second 12-month period; (c) $3,000 per Unit (30% per Unit) in the third 12-month period; or (d) $4,000 per Unit (40% per Unit) in the fourth 12-month period (no carry forward is required if such distributions are less than $5,000 per Unit (50% per Unit) in the fifth 12-month period because the Managing General Partner's subordination obligation terminates on the expiration of the fifth 12-month period); and (ii) reimbursing the Managing General Partner for any previous subordination payments to the extent cumulative cash distributions to Participants, including any subordination payments, would exceed: (a) $1,000 per Unit (10% per Unit) in the first 12-month period; (b) $2,000 per Unit (20% per Unit) in the second 12-month period; (c) $3,000 per Unit (30% per Unit) in the third 12-month period; (d) $4,000 per Unit (40% per Unit) in the fourth 12-month period; or (e) $5,000 per Unit (50% per Unit) 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 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 $250 per Unit (25% of $1,000 per Unit per year) or more assuming there is no subordination owed for any preceding period); (ii) the Managing General Partner shall not be required to return Partnership distributions previously received by it, even though a subordination obligation arises after the distributions; (iii) subject to the foregoing provisions of this section, only Partnership revenues in the current distribution period shall be debited or credited to the Managing General Partner as may be necessary to provide, to the extent possible, subordination distributions to the Participants and reimbursements to the Managing General Partner; (iv) no subordination payments to the Participants or reimbursements to the Managing General Partner shall be made after the expiration of the fifth 12-month subordination period; and 37 (v) subordination payments to the Participants shall be subject to any lien or priority required by the Managing General Partner's lenders pursuant to agreements previously entered into or subsequently entered into or renewed by 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 (other than Intangible Drilling Costs and Tangible Costs) and revenues charged or credited to the Participants as a group, which includes all revenue credited to the Participants under ss.5.01(b)(4), shall be allocated among the Participants, including the Managing General Partner to the extent of any optional subscription under ss.3.03(b)(2), in the ratio of their respective Units based on $10,000 per Unit regardless of the actual subscription price for a Participant's Units. Intangible Drilling Costs and Tangible Costs charged to the Participants as a group shall be allocated among the Participants, including the Managing General Partner to the extent of any optional subscription under ss.3.03(b)(2), in the ratio of the subscription price designated on their respective Subscription Agreements rather than the number of their respective Units. 5.01(c)(2). COSTS AND REVENUES NOT DIRECTLY ALLOCABLE TO A PARTNERSHIP WELL. Costs and revenues not directly allocable to a particular Partnership Well or additional operation shall be allocated among the Partnership Wells or additional operations in any manner the Managing General Partner in its reasonable discretion, shall select, and shall then be charged or credited in the same manner as costs or revenues directly applicable to the Partnership Well or additional operation are being charged or credited. 5.01(c)(3). MANAGING GENERAL PARTNER'S DISCRETION IN MAKING ALLOCATIONS FOR FEDERAL INCOME TAX PURPOSES. In determining the proper method of allocating charges or credits among the parties, 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, regardless of the number of interests owned by the party, the class of the interests and the time or manner in which the interests were acquired. 5.02(b). CHARGES AND CREDITS. 5.02(b)(1). GENERAL STANDARD. Except as otherwise provided in this Agreement, the Capital Account of each party shall be determined and maintained in accordance with Treas. Reg. ss.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 ss.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 ss.752 of the Code; and (iii) allocations to him of Partnership income and gain, or items thereof, including income and gain exempt from tax and income and gain described in Treas. Reg. ss.1.704-l(b)(2)(iv)(g), but excluding income and gain described in Treas. Reg. ss.1.704-l(b)(4)(i); 38 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 ss.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 ss.752 of the Code; (vi) allocations to him of Partnership expenditures described in ss.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. ss.1.704-l(b)(2)(iv)(g), but excluding items described in (vi) above, and loss or deduction described in Treas. Reg. ss.1.704-l(b)(4)(i) or (iii). 5.02(b)(2). EXCEPTION. If Treas. Reg. ss.1.704-l(b)(2)(iv) fails to provide guidance, Capital Account adjustments shall be made in a manner that: (i) maintains equality between the aggregate governing Capital Accounts of the parties and the amount of Partnership capital reflected on the Partnership's balance sheet, as computed for book purposes; (ii) is consistent with the underlying economic arrangement of the parties; and (iii) is based, wherever practicable, on federal tax accounting principles. 5.02(c). PAYMENTS TO THE MANAGING GENERAL PARTNER. The Capital Account of the Managing General Partner shall be reduced by payments to it pursuant to ss.4.04(a)(2) only to the extent of the Managing General Partner's distributive share of any Partnership deduction, loss, or other downward Capital Account adjustment resulting from the payments. 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 ss.704 and other provisions of the Code and the related rules, regulations and interpretations as may exist from time to time. 5.02(e). REVALUATIONS OF PROPERTY. In the discretion of the Managing General Partner the Capital Accounts of the parties may be increased or decreased to reflect a revaluation of Partnership property, including intangible assets such as goodwill, on a property-by-property basis except as otherwise permitted under ss.704(c) of the Code and the regulations thereunder, on the Partnership's books, in accordance with Treas. Reg. ss.1.704-l(b)(2)(iv)(f). 5.02(f). AMOUNT OF BOOK ITEMS. In cases where ss.704(c) of the Code or ss.5.02(e) applies, Capital Accounts shall be adjusted in accordance with Treas. Reg. ss.1.704-l(b)(2)(iv)(g) for allocations of depreciation, depletion, amortization and gain and loss, as computed for book purposes, with respect to the property. 5.03. ALLOCATION OF INCOME, DEDUCTIONS AND CREDITS. 5.03(a). IN GENERAL. 5.03(a)(1). DEDUCTIONS ARE ALLOCATED TO PARTY CHARGED WITH EXPENDITURE. To the extent permitted by law and except as otherwise provided in this Agreement, all deductions and credits, including, but not limited to, intangible drilling and development costs and depreciation, shall be allocated to the party who has been charged with the expenditure giving rise to the deductions and credits; and to the extent permitted by law, these parties shall be entitled to the deductions and credits in computing taxable income or tax liabilities to the exclusion of any other party. Also, any Partnership deductions that would be nonrecourse deductions if they were not attributable to a loan made or guaranteed by the Managing General Partner or its Affiliates shall be allocated to the Managing General Partner to the extent required by law. 5.03(a)(2). INCOME AND GAIN ALLOCATED IN ACCORDANCE WITH REVENUES. Except as otherwise provided in this Agreement, all items of income and gain, including gain on disposition of assets, shall be allocated in accordance with the related revenue allocations set forth in ss.5.01(b) and its subsections. 39 5.03(b). TAX BASIS OF EACH PROPERTY. Subject to ss.704(c) of the Code, the tax basis of each oil and gas property for computation of cost depletion and gain or loss on disposition shall be allocated and reallocated when necessary based on the capital interest in the Partnership as to the property and the capital interest in the Partnership for this purpose as to each property shall be considered to be owned by the parties in the ratio in which the expenditure giving rise to the tax basis of the property has been charged as of the end of the year. 5.03(c). GAIN OR LOSS ON OIL AND GAS PROPERTIES. Each party shall separately compute its gain or loss on the disposition of each natural gas and oil property in accordance with the provisions of ss.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 ss.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 ss.ss.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. As of the date of the Prospectus, tax credits are not available to the Partnership. If this changes in the future, however, and if a Partnership expenditure, whether or not deductible, that gives rise to a tax credit in a Partnership taxable year also gives rise to valid allocations of Partnership loss or deduction, or other downward Capital Account adjustments, for the year, then the parties' interests in the Partnership with respect to the credit, or the cost giving rise thereto, shall be in the same proportion as the parties' respective distributive shares of the loss or deduction, and adjustments. Identical principles shall apply in determining the parties' 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 party having a deficit Capital Account balance as of the end of the taxable year to which the allocation relates, if charged to the party, to the extent the Participant is not required to restore the deficit to the Partnership, taking into account: (i) adjustments that, as of the end of the year, reasonably are expected to be made to the party's Capital Account for depletion allowances with respect to the Partnership's natural gas and oil properties; (ii) allocations of loss and deduction that, as of the end of the year, reasonably are expected to be made to the party under ss.ss.704(e)(2) and 706(d) of the Code and Treas. Reg. ss.1.751-1(b)(2)(ii); and (iii) distributions that, as of the end of the year, reasonably are expected to be made to the party to the extent they exceed offsetting increases to the party's Capital Account, assuming for this purpose that the fair market value of Partnership property equals its adjusted tax basis, that reasonably are expected to occur during or prior to the Partnership taxable years in which the distributions reasonably are expected to be made; shall be charged to the Managing General Partner. Further, the Managing General Partner shall be credited with an additional amount of Partnership income or gain equal to the amount of the loss or deduction as quickly as possible to the extent such chargeback does not cause or increase deficit balances in the parties' Capital Accounts which are not required to be restored to the Partnership. 40 Notwithstanding any provisions of this Agreement to the contrary, if a party unexpectedly receives an adjustment, allocation, or distribution described in (i), (ii), or (iii) above, or any other distribution, which causes or increases a deficit balance in the party's Capital Account which is not required to be restored to the Partnership, the party shall be allocated items of income and gain, consisting of a pro rata portion of each item of Partnership income, including gross income, and gain for the year, in an amount and manner sufficient to eliminate the deficit balance as quickly as possible. 5.03(i). MINIMUM GAIN CHARGEBACK. To the extent there is a net decrease during a Partnership taxable year in the minimum gain attributable to a Partner nonrecourse debt, then any Partner with a share of the minimum gain attributable to the debt at the beginning of the year shall be allocated items of Partnership income and gain in accordance with Treas. Reg. ss.1.704-2(i). 5.03(j). PARTNERS' ALLOCABLE SHARES. Except as otherwise provided in this Agreement, each party's allocable share of Partnership income, gain, loss, deductions and credits shall be determined by 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 parties 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 party'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). SS.754 ELECTION. In the event of the transfer of an interest in the Partnership, or on the death of an individual party hereto, or in the event of the distribution of property to any party, the Managing General Partner may choose for the Partnership to file an election in accordance with the applicable Treasury Regulations to cause the basis of the Partnership's assets to be adjusted for federal income tax purposes as provided by ss.ss.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 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. 41 5.05(a)(4). DISTRIBUTIONS TO THE MANAGING GENERAL PARTNER. Cash distributions from the Partnership to the Managing General Partner shall only be made as follows: (a) in conjunction with distributions to Participants; and (b) out of funds properly allocated to the Managing General Partner's account. 5.05(a)(5). RESERVE. At any time after one year from the date each Partnership Well is placed into production, the Managing General Partner shall have the right to deduct each month from the Partnership's 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 the 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, except necessary operating capital, shall be distributed to the Participants in the ratio that the subscription price designated on each Participant's Subscription Agreement bears to the total subscription prices designated on all of the Participants' Subscription Agreements, as a return of capital. The Managing General Partner shall reimburse the Participants for the selling or other offering expenses, if any, allocable to the return of capital. For purposes of this subsection, "committed for expenditure" shall mean contracted for, actually earmarked for or allocated by the Managing General Partner to the Partnership's drilling operations, and "necessary operating capital" shall mean those funds which, in the opinion of the Managing General Partner, should remain on hand to assure continuing operation of the Partnership. 5.05(c). DISTRIBUTIONS ON WINDING UP. On the winding up of the Partnership distributions shall be made as provided in ss.7.02. 5.05(d). INTEREST AND RETURN OF CAPITAL. No party shall under any circumstances be entitled to any interest on amounts retained by the Partnership. Each Participant shall look only to his share of distributions, if any, from the Partnership for a return of his Capital Contribution. ARTICLE VI TRANSFER OF INTERESTS 6.01. TRANSFERABILITY. 6.01(a). RIGHTS OF ASSIGNEE. On a transfer 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 UNITS. 6.01(b)(1). AUTOMATIC CONVERSION. After all of the Partnership Wells have been drilled and completed, as determined by the Managing General Partner, the Managing General Partner shall file an amended certificate of limited partnership with the Secretary of State of the State of Delaware for the purpose of converting the Investor General Partner Units to Limited Partner Units. 6.01(b)(2). INVESTOR GENERAL PARTNERS SHALL HAVE CONTINGENT LIABILITY. On conversion the Investor General Partners shall be Limited Partners entitled to limited liability; however, they shall remain liable to the Partnership for any additional Capital Contribution required for their proportionate share of any Partnership obligation or liability arising before the conversion of their Units as provided in ss.3.05(b)(2). 6.01(b)(3). CONVERSION SHALL NOT AFFECT ALLOCATIONS. The conversion shall not affect the allocation to any Participant of any item of Partnership income, gain, loss, deduction or credit or other item of special tax significance other than Partnership liabilities, if any. Further, the conversion shall not affect any Participant's interest in the Partnership's natural gas and oil properties and unrealized receivables. 42 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 Units 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) except as provided by operation of law: (a) 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; and (b) Units may not be assigned to a person who is under the age of 18 or incompetent (unless an attorney-in-fact, guardian, custodian or conservator has been appointed to handle the affairs of that person) without the Managing General Partner's consent; (ii) the costs and expenses associated with the 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 Units are subject to the following additional restrictions set forth in ss.ss.6.02(a)(1) and 6.02(a)(2). 6.02(a)(1). TAX LAW RESTRICTIONS. Subject to transfers permitted by ss.6.04 and transfers by operation of law, no sale, assignment, exchange, or transfer of a Unit shall be made which, in the opinion of counsel to the Partnership, would result in the Partnership being either: (i) terminated for tax purposes under ss.708 of the Code; or (ii) treated as a "publicly-traded" partnership for purposes of ss.469(k) of the Code. 6.02(a)(2). SECURITIES LAWS RESTRICTION. Subject to transfers permitted by ss.6.04 and transfers by operation of law, no Unit shall be sold, assigned, pledged, hypothecated, or transferred which, in the opinion of counsel to the Partnership, would result in the violation of any applicable federal or state securities laws. Transfers are also subject to any conditions contained in the Subscription Agreement and Exhibit (B) to the Prospectus. 6.02(a)(3). SUBSTITUTE PARTICIPANT. 6.02(a)(3)(a). PROCEDURE TO BECOME SUBSTITUTE PARTICIPANT. Subject to ss.ss.6.02(a)(1) and 6.02(a)(2), an assignee of a Participant's Unit shall become a substituted Participant entitled to all the rights of a Participant if, and only if: (i) the assignor gives the assignee the right; (ii) the assignee pays to the Partnership all costs and expenses incurred in connection with the substitution; and (iii) the assignee executes and delivers the instruments necessary to establish that a legal transfer has taken place and to confirm the agreement of the assignee to be bound by all of the terms 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. 43 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 as follows: (i) midnight of the last day of the calendar month in which it is made; or (ii) at the Managing General Partner's election, 7:00 A.M. of the following day. 6.02(b)(2). TRANSFER DOES NOT RELIEVE TRANSFEROR OF CERTAIN COSTS. No transfer, including a transfer of less than all of a Participant's Units or the transfer of Units to more than one party, shall relieve the transferor of its responsibility for its proportionate part of any expenses, obligations and liabilities under this Agreement related to the Units so transferred, whether arising before or after the transfer. 6.02(b)(3). 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 notice of 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 ss.8.01 and its subsections. This party shall continue to exercise all rights applicable to the Units 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 these borrowings and costs, interest or other charges related to the borrowings shall be borne and paid separately by the Managing General Partner. In no event shall the repayments, costs, interest, or other charges related to the borrowing be charged to the account of the Participants. In addition, subject to a required participation of not less than 1% in the Partnership as Managing General Partner, the Managing General Partner may withdraw a property interest held by the Partnership in the form of a Working Interest in the Partnership's Wells equal to or less than its respective interest in the revenues of the Partnership if: (i) the withdrawal is necessary to satisfy the bona fide request of its creditors; or (ii) the withdrawal is approved by Participants whose Units equal a majority of the total Units. 6.04. PRESENTMENT. 6.04(a). IN GENERAL. Participants shall have the right to present their Units to the Managing General Partner for purchase subject to the conditions and limitations set forth in this section. A Participant, however, is not obligated to present his Units for purchase. 44 The Managing General Partner shall not be obligated to purchase more than 5% of the Units in any calendar year and this 5% limit may not be waived. The Managing General Partner shall not purchase less than one Unit unless the lesser amount represents the Participant's entire interest in the Partnership, however, the Managing General Partner may waive this limitation. A Participant may present his Units in writing to the Managing General Partner every year beginning with the fifth calendar year after the Offering Termination Date subject to the following conditions: (i) the presentment must be made within 120 days of the reserve report set forth inss.4.03(b)(3); (ii) in accordance with Treas. Reg. ss.1.7704-1(f), the purchase may not be made until at least 60 calendar days after the Participant notifies the Partnership in writing of the Participant's intention to exercise the presentment right; and (iii) the purchase shall not be considered effective until the presentment price has been paid in cash to the Participant. 6.04(b). REQUIREMENT FOR INDEPENDENT PETROLEUM CONSULTANT. The amount of the presentment price attributable to Partnership reserves shall be determined based on the last reserve report of the Partnership prepared by the Managing General Partner and reviewed by an Independent Expert. The Managing General Partner shall estimate the present worth of future net revenues attributable to the Partnership's interest in the Proved Reserves. 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 natural gas on the existing natural gas contracts at the time of the purchase. The calculation of the presentment price shall be as set forth in ss.6.04(c). 6.04(c). CALCULATION OF PRESENTMENT PRICE. The presentment price shall be based on the Participant's share of the net assets and liabilities of the Partnership and allocated pro rata to each Participant in the ratio that his number of Units bears to the total number of Units. 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 ss.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 (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 natural gas, oil 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. 45 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 purchase; 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 natural gas, oil 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 Units presented at any time are to be purchased, then the Participants whose Units are to be purchased will be selected by lot. The Managing General Partner's obligation to purchase Units presented may be discharged for its benefit by a third-party or an Affiliate. The Units of the selling Participant will be transferred to the party who pays for it. A selling Participant will be required to deliver an executed assignment of his Units, together with any 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 it: (i) does not have sufficient cash flow; or (ii) is unable to borrow funds for this purpose on terms it deems reasonable. In addition, the presentment feature may be conditioned, in the Managing General Partner's sole discretion, on the Managing General Partner's receipt of an opinion of counsel that the transfers will not cause the Partnership to be treated as a "publicly traded partnership" under the Code. The Managing General Partner shall hold the purchased Units for its own account and not for resale. ARTICLE VII DURATION, DISSOLUTION, AND WINDING UP 7.01. DURATION. 7.01(a). FIFTY YEAR TERM. The Partnership shall continue in existence for a term of 50 years from the effective date of this Agreement unless sooner terminated as set forth below. 46 7.01(b). TERMINATION. The Partnership shall terminate following the occurrence of: (i) a Final Terminating Event; or (ii) any event which under the Delaware Revised Uniform Limited Partnership Act causes the dissolution of a limited partnership. 7.01(c). CONTINUANCE OF PARTNERSHIP EXCEPT ON FINAL TERMINATING EVENT. Other than the occurrence of a Final Terminating Event, the Partnership or any successor limited partnership shall not be wound up, but shall be continued by the parties and their respective successors as a successor limited partnership under all 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. On the occurrence of a Final Terminating Event the affairs of the Partnership shall be wound up and there shall be distributed to each of the parties its Distribution Interest in the remaining Partnership assets. 7.02(b). TIME OF LIQUIDATING DISTRIBUTION. To the extent practicable and in accordance with sound business practices in the judgment of the Managing General Partner, liquidating distributions shall be made by: (i) the end of the taxable year in which liquidation occurs, determined without regard to ss.706(c)(2)(A) of the Code; or (ii) if later, within 90 days after the date of the liquidation. Notwithstanding, the following amounts are not required to be distributed within the foregoing time periods so long as the withheld amounts are distributed as soon as practical: (i) amounts withheld for reserves reasonably required for liabilities of the Partnership; and (ii) installment obligations owed to the Partnership. 7.02(c). IN-KIND DISTRIBUTIONS. The Managing General Partner shall not be obligated to offer in-kind property distributions to the Participants, but may do so, in its discretion. Any in-kind property distributions to the Participants shall be made to a liquidating trust or similar entity for the benefit of the Participants, unless at the time of the distribution: (i) the Managing General Partner offers the individual Participants the election of receiving in-kind property distributions and the Participants accept the offer after being advised of the risks associated with direct ownership; or (ii) there are alternative arrangements in place which assure the Participants that they will not, at any time, be responsible for the operation or disposition of Partnership properties. If the Managing General Partner has not received a Participant's consent within 30 days after the Managing General Partner mailed the request for consent, then it shall be presumed that the Participant has refused his consent. 7.02(d). SALE IF NO CONSENT. Any Partnership asset which would otherwise be distributed in-kind to a Participant, except for the failure or refusal of the Participant to give his written consent to the distribution, may instead be sold by the Managing General Partner at the best price reasonably obtainable from an independent third-party, who is not an Affiliate of the Managing General Partner or to itself or its Affiliates, including an Affiliated Income Program, at fair market value as determined by an Independent Expert selected by the Managing General Partner. ARTICLE VIII MISCELLANEOUS PROVISIONS 8.01. NOTICES. 8.01(a). METHOD. Any notice required under this Agreement shall be: 47 (i) in writing; and (ii) given by mail or wire addressed to the party to receive the notice at the address designated in ss.1.03. If there is a transfer of Units under this Agreement, no notice to the transferee shall be required, nor shall the transferee have any rights under this Agreement, until notice has 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 Units under this Agreement to more than one party, then notice to any owner of any interest in the Units shall be notice to all owners of the Units. 8.01(b). CHANGE IN ADDRESS. The address of any party to this Agreement may be changed by written notice as follows: (i) to the Participants if there is a change of address by the Managing General Partner; or (ii) to the Managing General Partner if there is a change of address by a Participant. 8.01(c). TIME NOTICE DEEMED GIVEN. If the notice is given by the Managing General Partner, then the notice shall be considered given, and any applicable time shall run, from the date the notice is placed in the mail or delivered to the 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 pursuant to ss.7.02(c) or when this Agreement expressly requires affirmative approval of a Participant, any Participant who fails to respond in writing within the time specified to a request by the Managing General Partner as set forth below, for approval of or concurrence in a proposed action shall be conclusively deemed to have approved the action. 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 State of Delaware, provided, however, this section shall not be deemed to limit causes of action for violations of federal or state securities law to the laws of the State of Delaware. Neither this Agreement nor the Subscription Agreement shall require mandatory venue or mandatory arbitration of any or all claims by Participants against the Sponsor. 8.04. AGREEMENT IN COUNTERPARTS. This Agreement may be executed in counterpart and shall be binding on all parties executing this or similar agreements from and after the date of execution by each party. 8.05. AMENDMENT. 8.05(a). PROCEDURE FOR AMENDMENT. No changes in this Agreement shall be binding unless: 48 (i) proposed in writing by the Managing General Partner, and adopted with the consent of Participants whose Units equal a majority of the total Units; or (ii) proposed in writing by Participants whose Units equal 10% or more of the total Units and approved by an affirmative vote of Participants whose Units equal a majority of the total Units. 8.05(b). CIRCUMSTANCES UNDER WHICH THE MANAGING GENERAL PARTNER ALONE MAY AMEND. The Managing General Partner is authorized to amend this Agreement and its exhibits without the consent of Participants in any way deemed necessary or desirable by it to do any or all of the following: (i) add or substitute in the case of an assigning party additional Participants; (ii) enhance the tax benefits of the Partnership to the parties; or (iii) satisfy any requirements, conditions, guidelines, options, or elections contained in any opinion, directive, order, ruling, or regulation of the SEC, the IRS, or any other federal or state agency, or in any federal or state statute, compliance with which it deems to be in the best interest of the Partnership. 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 on and inure to the benefit of the parties, their heirs, devisees, personal representatives, successors and assigns, and shall run with the interests subject to this Agreement. The terms "Partnership," "Limited Partner," "Investor General Partner," "Participant," "Partner," "Managing General Partner," "Operator," or "parties" shall equally apply to any successor limited partnership, and any heir, devisee, personal representative, successor or assign of a party. IN WITNESS WHEREOF, the parties hereto set their hands as of the day and year hereinabove shown. ATLAS: ATLAS RESOURCES, INC. Managing General Partner By: -------------------------------- 49 EXHIBIT (I-A) FORM OF MANAGING GENERAL PARTNER SIGNATURE PAGE EXHIBIT (I-A) MANAGING GENERAL PARTNER SIGNATURE PAGE Attached to and made a part of the AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP of ATLAS AMERICA PUBLIC #14-2004 L.P. The undersigned agrees: 1. to serve as the Managing General Partner of ATLAS AMERICA PUBLIC #14-2004 L.P. (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 ss.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 _______ , 2004. ATLAS RESOURCES, INC. MANAGING GENERAL PARTNER By: ______________________________ EXHIBIT (I-B) FORM OF SUBSCRIPTION AGREEMENT ATLAS AMERICA PUBLIC #14-2004 L.P. - -------------------------------------------------------------------------------- SUBSCRIPTION AGREEMENT - -------------------------------------------------------------------------------- I, the undersigned, hereby offer to purchase Units of Atlas America Public #14-2004 L.P. in the amount set forth on the Signature Page of this Subscription Agreement and on the terms described in the current Prospectus for Atlas America Public #14-2004 Program, as supplemented or amended from time to time. I acknowledge and agree that my execution of this Subscription Agreement also constitutes my execution of the Agreement of Limited Partnership (the "Partnership Agreement") the form of which is attached as Exhibit (A) to the Prospectus and I agree to be bound by all of the terms and conditions of the Partnership Agreement if my subscription is accepted by Atlas Resources, Inc., the Managing General Partner. I understand and agree that I may not assign this offer, nor may it be withdrawn after it has been accepted by the Managing General Partner. I hereby irrevocably constitute and appoint the Managing General Partner, and its duly authorized agents, my agent and attorney-in-fact, in my name, place and stead, to make, execute, acknowledge, swear to, file, record and deliver the Agreement of Limited Partnership and any certificates related thereto. In order to induce the Managing General Partner to accept this subscription, I hereby represent, warrant, covenant and agree as follows:
INVESTOR'S CO-INVESTOR'S INITIALS INITIALS - -------- -------- _____ _____ I have received the Prospectus. _____ _____ I (other than if I am a Minnesota or Maine resident) recognize and understand that: o 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; o the transferability of the Units is restricted; and o 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: o my own account; o for investment purposes and not for the account of others; and o with no present intention of reselling them. _____ _____ If an individual, I am: o a citizen of the United States of America; and o 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. I am at least twenty-one years of age and empowered and duly authorized under a governing document, trust instrument, charter, certificate of incorporation, by-law provision or the like to enter into this Subscription Agreement and to perform the transactions contemplated by the Prospectus, including its exhibits.
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INVESTOR'S CO-INVESTOR'S INITIALS INITIALS - -------- -------- (a) If I purchase limited partner units and I am a resident of: o ALABAMA, o KENTUCKY, o OREGON, o ALASKA, o LOUISIANA, o RHODE ISLAND, o ARIZONA, o MAINE, o SOUTH CAROLINA, o ARKANSAS, o MARYLAND, o SOUTH DAKOTA, o COLORADO, o MASSACHUSETTS, o TENNESSEE, o CONNECTICUT, o MINNESOTA, o TEXAS, o DELAWARE, o MISSISSIPPI, o UTAH, o DISTRICT OF COLUMBIA, o MISSOURI, o VERMONT, o FLORIDA, o MONTANA, o VIRGINIA, o GEORGIA, o NEBRASKA, o WASHINGTON o HAWAII, o NEVADA, o WEST VIRGINIA, o IDAHO, o NEW JERSEY, o WISCONSIN, OR o ILLINOIS, o NEW MEXICO o WYOMING, o INDIANA, o NEW YORK, o IOWA, o NORTH DAKOTA, o KANSAS, o OKLAHOMA, then I must have either: _____ _____ o a minimum net worth of $225,000, exclusive of home, home furnishings, and automobiles; or _____ _____ o a minimum net worth of $60,000, exclusive of home, home furnishings, and automobiles, 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. (b) If I purchase limited partner units and I am a resident of: o CALIFORNIA, o NEW HAMPSHIRE, o OHIO, o MICHIGAN, o NORTH CAROLINA, o PENNSYLVANIA, 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 purchase investor general partner units and I am a resident of: o ALASKA, o ILLINOIS, o RHODE ISLAND, o COLORADO, o LOUISIANA, o SOUTH CAROLINA, o CONNECTICUT, o MARYLAND, o UTAH, o DELAWARE, o MONTANA, o VIRGINIA, o DISTRICT OF COLUMBIA, o NEBRASKA, o WEST VIRGINIA, o FLORIDA, o NEVADA, o WISCONSIN, OR o GEORGIA, o NEW JERSEY, o WYOMING, o HAWAII, o NEW YORK, o IDAHO, o NORTH DAKOTA,
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INVESTOR'S CO-INVESTOR'S INITIALS INITIALS - -------- -------- then I must have either: _____ _____ o a net worth of at least $225,000, exclusive of home, furnishings and automobiles; or _____ _____ o a net worth, exclusive of home, furnishings and automobiles, of: o at least $60,000; and o 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. _____ _____ (d) IF I PURCHASE INVESTOR GENERAL PARTNER UNITS AND I AM A RESIDENT OF: o ALABAMA, o MASSACHUSETTS, o OKLAHOMA, o ARIZONA, o MICHIGAN, o OREGON, o ARKANSAS, o MINNESOTA, o PENNSYLVANIA, o CALIFORNIA, o MISSISSIPPI, o SOUTH DAKOTA, o INDIANA, o MISSOURI, o TENNESSEE, o IOWA, o NEW HAMPSHIRE, o TEXAS, o KANSAS, o NEW MEXICO, o VERMONT OR o KENTUCKY, o NORTH CAROLINA, o WASHINGTON, o MAINE, o OHIO, 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. _____ _____ (e) 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 (other than if I am a Minnesota or Maine resident) understand that if I am an Investor General Partner, then I will have unlimited joint and several liability for Partnership obligations and liabilities including amounts in excess of my subscription to the extent the obligations and liabilities exceed the following: o the Partnership's insurance proceeds; o the Partnership's assets; and o indemnification by the Managing General Partner. Insurance may be inadequate to cover these liabilities and there is no insurance coverage for certain claims. _____ _____ I (other than if I am a Minnesota or Maine resident) understand that if I am a Limited Partner, then I may only use my Partnership losses to the extent of my net passive income from passive activities in the year, with any excess losses being deferred. _____ _____ I (other than if I am a Minnesota or Maine resident) understand that no state or federal governmental authority has made any finding or determination relating to the fairness for public investment of the Units and no state or federal governmental authority has recommended or endorsed or will recommend or endorse the Units.
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INVESTOR'S CO-INVESTOR'S INITIALS INITIALS - -------- -------- _____ _____ I (other than if I am a Minnesota or Maine resident) understand that the Selling Agent or registered representative is required to inform me and the other potential investors of all pertinent facts relating to the Units, including the following: o the risks involved in the offering, including the speculative nature of the investment and the speculative nature of drilling for natural gas and oil; o the financial hazards involved in the offering, including the risk of losing my entire investment; o the lack of liquidity of my investment; o the restrictions on transferability of my Units; o the background of the Managing General Partner and the Operator; o the tax consequences of my investment; and o 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: o the person has been given your legal power of attorney to sign on your behalf; and o you meet all of the conditions in the Prospectus and this Subscription Agreement. In the case of sales to fiduciary accounts, the minimum standards set forth in the Prospectus and this Subscription Agreement must be met by: o the beneficiary; o the fiduciary account; or o by the donor or grantor who directly or indirectly supplies the funds to purchase the Partnership Units if the donor or grantor is the fiduciary. Your execution of the Subscription Agreement constitutes your binding offer to buy Units in the Partnership. Once you subscribe you may withdraw your subscription only by providing the Managing General Partner with written notice of your withdrawal before your subscription is accepted by the Managing General Partner. The Managing General Partner has the discretion to refuse to accept your subscription without liability to you. Subscriptions will be accepted or rejected by the Partnership within 30 days of their receipt. If your subscription is rejected, then all of your funds will be returned to you immediately. If your subscription is accepted before the first closing, then you will be admitted as a Participant not later than 15 days after the release from escrow of the investors' funds to the Partnership. If your subscription is accepted after the first closing, then you will be admitted into the Partnership not later than the last day of the calendar month in which your subscription was accepted by the Partnership. The Managing General Partner will do the following: o not complete a sale of Units to you until at least five business days after the date you receive a final Prospectus; and 4 o 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 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. 5 - -------------------------------------------------------------------------------- SIGNATURE PAGE OF SUBSCRIPTION AGREEMENT - -------------------------------------------------------------------------------- I, the undersigned, agree to purchase ________ Units at $10,000 per Unit in ATLAS AMERICA PUBLIC #14-2004 L.P. (the "Partnership") as (check one):
|_| INVESTOR GENERAL PARTNER SUBSCRIPTION PRICE |_| LIMITED PARTNER $_______________________ (______________________# Units) INSTRUCTIONS ============================================================================================================================= Make your check payable to: "Atlas America Public #14-2004 L.P., 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 personally My Home Address (Do not use P.O. Box) sign this Signature Page.) - ------------------------------------------------- ------------------------------------------------------ Print Name - ------------------------------------------------- ------------------------------------------------------ Signature - ------------------------------------------------- ------------------------------------------------------ Print Name My Address for Distributions if Different from Above - ------------------------------------------------- Signature ------------------------------------------------------ ------------------------------------------------------ Date: _______________ My Tax I.D. No. (Social Security No.): _________________ Account No.: _________________________________________ My Telephone No.: Business ___________________ Home ________________________ My E-mail Address: ____________________________________ (CHECK ONE): I am a: |_| Calendar Year Taxpayer |_| Fiscal Year Taxpayer (CHECK IF APPLICABLE): I am a: |_| Farmer (2/3 or more of my gross income in 2004 or 2003 is from farming) (CHECK ONE): OWNERSHIP OF THE UNITS- |_| Tenants-in-Common |_| Partnership |_| Joint Tenancy |_| C Corporation |_| Individual |_| S Corporation |_| Trust |_| Community Property |_| Limited Liability Company |_| Other NAME OF TRUST, CORPORATION, LLC, PARTNERSHIP: NAME _________________________________________________________________________ (ENCLOSE SUPPORTING DOCUMENTS.)
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- ----------------------------------------------------------------------------------------------------------------------------- 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. - ------------------------------------------------------------ ------------------------------------------------------ Name of Registered Representative and CRD Number Name of Broker/Dealer - ------------------------------------------------------------ ------------------------------------------------------ Signature of Registered Representative Broker/Dealer CRD Number Registered Representative Office Address: Broker/Dealer E-mail Address:_________________________ - ------------------------------------------------------------ - ------------------------------------------------------------ Phone Number: ---------------------------------------------- Facsimile Number: ------------------------------------------ E-mail Address: -------------------------------------------- - ------------------------------------------------------------ Company Name (if other than Broker/Dealer Name) NOTICE TO BROKER-DEALER: Send SUBSCRIPTION DOCUMENTS completed and signed with CHECK MADE PAYABLE TO: "ATLAS PUBLIC #14-2004 L.P., ESCROW AGENT, NATIONAL CITY BANK OF PA" to: Mr. Justin Atkinson Anthem Securities, Inc. 311 Rouser Road P.O. Box 926 Moon Township, Pennsylvania 15108-0926 (412) 262-1680 (412) 262-7430 (FAX) - ----------------------------------------------------------------------------------------------------------------------------- TO BE COMPLETED BY THE MANAGING GENERAL PARTNER - ----------------------------------------------------------------------------------------------------------------------------- ACCEPTED THIS ______ day ATLAS RESOURCES, INC., of _________________ , 2004 MANAGING GENERAL PARTNER By:_____________________________________
2 EXHIBIT (II) FORM OF DRILLING AND OPERATING AGREEMENT FOR ATLAS AMERICA PUBLIC #14-2004 L.P. [ATLAS AMERICA PUBLIC #14-2005(_____) L.P.] INDEX
SECTION PAGE 1. Assignment of Well Locations; Representations and Indemnification Associated with the Assignment of the Lease; Designation of Additional Well Locations; Outside Activities Are Not Restricted..........................................................................................1 2. Drilling of Wells; Timing; Depth; Interest of Developer; Right to Substitute Well Locations.................2 3. Operator - Responsibilities in General; Covenants; Term.....................................................3 4. Operator's Charges for Drilling and Completing Wells; Payment; Completion Determination; Dry Hole Determination; Excess Funds and Cost Overruns - Intangible Drilling Costs; Excess Funds and Cost Overruns - Tangible Costs....................................................................4 5. Title Examination of Well Locations; Developer's Acceptance and Liability; Additional Well Locations........7 6. Operations Subsequent to Completion of the Wells; Fee Adjustments; Extraordinary Costs; Pipelines; Price Determinations; Plugging and Abandonment...................................................7 7. Billing and Payment Procedure with Respect to Operation of Wells; Disbursements; Separate Account for Sale Proceeds; Records and Reports; Additional Information.......................................................9 8. Operator's Lien; Right to Collect From Oil or Gas Purchaser................................................10 9. Successors and Assigns; Transfers; Appointment of Agent....................................................11 10. Operator's Insurance; Subcontractors' Insurance; Operator's Liability......................................12 11. Internal Revenue Code Election; Relationship of Parties; Right to Take Production in Kind..................13 12. Effect of Force Majeure; Definition of Force Majeure; Limitation...........................................14 13. Term.......................................................................................................14 14. Governing Law; Invalidity..................................................................................14 15. Integration; Written Amendment.............................................................................14 16. Waiver of Default or Breach................................................................................14 17. Notices....................................................................................................15 18. Interpretation.............................................................................................15 19. Counterparts...............................................................................................15 Signature Page.............................................................................................15
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 _______________, 200____, by and between ATLAS RESOURCES, INC., a Pennsylvania corporation (hereinafter referred to as "Atlas" or "Operator"), and ATLAS AMERICA PUBLIC #14-2004 L.P. [Atlas America Public #14-2005(_____) L.P.], a Delaware limited partnership, (hereinafter referred to as the "Developer"). WITNESSETH THAT: WHEREAS, the Operator, by virtue of the Oil and Gas Leases (the "Leases") described on Exhibit A attached to and made a part of this Agreement, has certain rights to develop the ____________ (______) initial well locations (the "Initial Well Locations") identified on the maps attached to and made a part of this Agreement as Exhibits A-l through A-______; WHEREAS, the Developer, subject to the terms and conditions of this Agreement, desires to acquire certain of the Operator's rights to develop the Initial Well Locations and to provide for the development on the terms and conditions set forth in this Agreement of additional well locations ("Additional Well Locations") 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 (collectively the "Well Locations") and to operate the wells completed on the Well Locations, on the terms and conditions set forth in this Agreement; NOW THEREFORE, in consideration of the mutual covenants herein contained and subject to the terms and conditions hereinafter set forth, the parties hereto, intending to be legally bound, hereby agree as follows: 1. ASSIGNMENT OF WELL LOCATIONS; REPRESENTATIONS AND INDEMNIFICATION ASSOCIATED WITH THE ASSIGNMENT OF THE LEASE; DESIGNATION OF ADDITIONAL WELL LOCATIONS; OUTSIDE ACTIVITIES ARE NOT RESTRICTED. (a) ASSIGNMENT OF WELL LOCATIONS. The Operator shall execute an assignment of an undivided percentage of Working Interest in the Well Location acreage for each well to the Developer as shown on Exhibit A attached hereto, which assignment shall be limited to a depth from the surface to the ___ of the ______________ formation (the "Objective Formation"). In the event, however, that hydrocarbons are encountered in quantities that Operator believes to be in paying quantities and drilling ceases before the Objective Formation is penetrated, then Operator shall execute an assignment limited to a depth from the surface to the deepest depth penetrated at the cessation of drilling operations. The assignment shall be substantially in the form of Exhibit B attached to and made a part of this Agreement. The amount of acreage included in each Initial Well Location and the configuration of the Initial Well Location are indicated on the maps attached as Exhibits A-l through A-______. The amount of acreage included in each Additional Well Location and the configuration of the Additional Well Location shall be indicated on the maps to be attached as exhibits to the applicable addendum to this Agreement as provided in sub-section (c) below. (b) REPRESENTATIONS AND INDEMNIFICATION ASSOCIATED WITH THE ASSIGNMENT OF THE LEASE. The Operator represents and warrants to the Developer that: (i) the Operator is the lawful owner of the Lease and rights and interest under the Lease and of the personal property on the Lease or used in connection with the Lease; (ii) the Operator has good right and authority to sell and convey the rights, interest, and property; (iii) the rights, interest, and property are free and clear from all liens and encumbrances; and (iv) all rentals and royalties due and payable under the Lease have been duly paid. 1 These representations and warranties shall also be included in each recorded assignment of the acreage included in each Initial Well Location and Additional Well Location designated pursuant to sub-section (c) below, substantially in the manner set forth in 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 above representations and warranties. It is understood and agreed that, except as specifically set forth above, the Operator makes no warranty or representation, express or implied, as to its title or the title of the lessors in and to the lands or oil and gas interests covered by said Leases. (c) DESIGNATION OF ADDITIONAL WELL LOCATIONS. If the parties hereto desire to designate Additional Well Locations to be developed in accordance with the terms and conditions of this Agreement, then the parties shall execute an addendum substantially in the form of Exhibit C attached to and made a part of this Agreement (Exhibit "C") specifying: (i) the undivided percentage of Working Interest and the Oil and Gas Leases to be included as Leases under this Agreement; (ii) the amount and configuration of acreage included in each Additional Well Location on maps attached as exhibits to the addendum; and (iii) their agreement that the Additional Well Locations shall be developed in accordance with the terms and conditions of this Agreement. (d) OUTSIDE ACTIVITIES ARE NOT RESTRICTED. It is understood and agreed that the assignment of rights under the Leases and the oil and gas development activities contemplated by this Agreement relate only to the Initial Well Locations and the Additional Well Locations. Nothing contained in this Agreement shall be interpreted to restrict in any manner the right of each of the parties to conduct without the participation of the other party any additional activities relating to exploration, development, drilling, production, or delivery of oil and gas on lands adjacent to or in the immediate vicinity of the Well Locations or elsewhere. 2. DRILLING OF WELLS; TIMING; DEPTH; INTEREST OF DEVELOPER; RIGHT TO SUBSTITUTE WELL LOCATIONS. (a) DRILLING OF WELLS. Operator, as Developer's independent contractor, agrees to drill, complete (or plug) and operate ____________ (_____) oil and gas wells on the ____________ (______) Initial Well Locations in accordance with the terms and conditions of this Agreement. Developer, as a minimum commitment, agrees to participate in and pay the Operator's charges for drilling and completing the wells and any extra costs pursuant to Section 4 in proportion to the share of the Working Interest owned by the Developer in the wells with respect to all initial wells. It is understood and agreed that, subject to sub-section (e) below, Developer does not reserve the right to decline participation in the drilling of any of the initial wells to be drilled under this Agreement. (b) TIMING. Operator shall begin drilling the first well within thirty (30) days after the date of this Agreement, and shall begin drilling each of the other initial wells for which payment is made pursuant to Section 4(b) of this Agreement before the close of the 90th day after the close of the calendar year in which this Agreement is entered into by Operator and the Developer. Subject to the foregoing time limits, Operator shall determine the timing of and the order of drilling the Initial Well Locations. (c) DEPTH. All of the wells to be drilled under this Agreement (c) shall be: (i) drilled and completed (or plugged) in accordance with the generally accepted and customary oil and gas field practices and techniques then prevailing in the geographical area of the Well Locations; and (ii) drilled to a depth sufficient to test thoroughly the objective formation or the deepest assigned depth, whichever is less. 2 (d) INTEREST OF DEVELOPER. Except as otherwise provided in this Agreement, all costs, expenses, and liabilities incurred in connection with the drilling and other operations and activities contemplated by this Agreement shall be borne and paid, and all wells, gathering lines of up to approximately 2,500 feet on the Well Location, in connection with a natural gas well, equipment, materials, and facilities acquired, constructed or installed under this Agreement shall be owned, by the Developer in proportion to the share of the Working Interest owned by the Developer in the wells. Subject to the payment of lessor's royalties and other royalties and overriding royalties, if any, production of oil and gas from the wells to be drilled under this Agreement shall be owned by the Developer in proportion to the share of the Working Interest owned by the Developer in the wells. (e) RIGHT TO SUBSTITUTE WELL LOCATIONS. Notwithstanding the provisions of sub-section (a) above, if the Operator or Developer determines in good faith, with respect to any Well Location, before operations begin under this Agreement on the Well Location, that it would not be in the best interest of the parties to drill a well on the Well Location, then the party making the determination shall notify the other party of its determination and its basis for its determination and, unless otherwise instructed by Developer, the well shall not be drilled. This determination may be based on: (i) the production or failure of production of any other wells which may have been recently drilled in the immediate area of the Well Location; (ii) newly discovered title defects; or (iii) any other evidence with respect to the Well Location as may be obtained. If the well is not drilled, then Operator shall promptly propose a new well location (including all information for the Well Location as Developer may reasonably request) to be substituted for the original Well Location. Developer shall then have seven (7) business days to either reject or accept the proposed new well location. If the new well location is rejected, then Operator shall promptly propose another substitute well location pursuant to the provisions of this sub-section. Once the Developer accepts a substitute well location or does not reject it within 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 of this Agreement. 3. OPERATOR - RESPONSIBILITIES IN GENERAL; COVENANTS; TERM. (a) OPERATOR - RESPONSIBILITIES IN GENERAL. Atlas shall be the Operator of the wells and Well Locations subject to this Agreement and, as the Developer's independent contractor, shall, in addition to its other obligations under this Agreement do the following: (i) arrange for drilling and completing the wells and, if a gas well, installing the necessary gas gathering line systems and connection facilities; (ii) make the technical decisions required in drilling, testing, completing, and operating the wells; (iii) manage and conduct all field operations in connection with the drilling, testing, completing, equipping, operating, and producing the wells; (iv) maintain all wells, equipment, gathering lines if a gas well, and facilities in good working order during their useful lives; and (v) perform the necessary administrative and accounting functions. In performing the work contemplated by this Agreement, Operator is an independent contractor with authority to control and direct the performance of the details of the work. (b) COVENANTS. Operator covenants and agrees that under this Agreement: (i) it shall perform and carry on (or cause to be performed and carried on) its duties and obligations in a good, prudent, diligent, and workmanlike manner using technically sound, acceptable oil and gas field practices then prevailing in the geographical area of the Well Locations; 3 (ii) all drilling and other operations conducted by, for and under the control of Operator shall conform in all respects to federal, state and local laws, statutes, ordinances, regulations, and requirements; (iii) unless otherwise agreed in writing by the Developer, all work performed pursuant to a written estimate shall conform to the technical specifications set forth in the written estimate and all equipment and materials installed or incorporated in the wells and facilities shall be new or used and of good quality; (iv) in the course of conducting operations, it shall comply with all terms and conditions, other than any minimum drilling commitments, of the Leases (and any related assignments, amendments, subleases, modifications and supplements); (v) it shall keep the Well Locations and all wells, equipment and facilities located on the Well Locations free and clear of all labor, materials and other liens or encumbrances arising out of operations; (vi) it shall file all reports and obtain all permits and bonds required to be filed with or obtained from any governmental authority or agency in connection with the drilling or other operations and activities; and (vii) it will provide competent and experienced personnel to supervise drilling, completing (or plugging), and operating the wells and use the services of competent and experienced service companies to provide any third party services necessary or appropriate in order to perform its duties. (c) TERM. Atlas shall serve as Operator under this Agreement until the earliest of: (i) the termination of this Agreement pursuant to Section 13; (ii) the termination of Atlas as Operator by the Developer at any time in the Developer's discretion, with or without cause on sixty (60) days' advance written notice to the Operator; or (iii) the resignation of Atlas as Operator under this Agreement which may occur on ninety (90) days' written notice to the Developer at any time after five (5) years from the date of this Agreement, it being expressly understood and agreed that Atlas shall have no right to resign as Operator before the expiration of the five-year period. Any successor Operator shall be selected by the Developer. Nothing contained in this sub-section shall relieve or release Atlas or the Developer from any liability or obligation under this Agreement which accrued or occurred before Atlas' removal or resignation as Operator under this Agreement. On any change in Operator under this provision, the then present Operator shall deliver to the successor Operator possession of all records, equipment, materials and appurtenances used or obtained for use in connection with operations under this Agreement and owned by the Developer. 4. OPERATOR'S CHARGES FOR DRILLING AND COMPLETING WELLS; PAYMENT; COMPLETION DETERMINATION; DRY HOLE DETERMINATION; EXCESS FUNDS AND COST OVERRUNS-INTANGIBLE DRILLING COSTS; EXCESS FUNDS AND COST OVERRUNS-TANGIBLE COSTS. (a) OPERATOR'S CHARGES FOR DRILLING AND COMPLETING WELLS. All oil and gas wells which are drilled and completed under this Agreement 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 the wells shall be set forth in an Authority for Expenditure ("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 well. This includes 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 examinations, logging, cementing, fracturing, casing, meters (other than utility purchase meters), connection facilities, salt water collection tanks, separators, siphon string, rabbit, tubing, an average of 2,500 feet of gathering line per well, in connection with a gas well, and geological and engineering services. 4 (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 and Tangible Costs as those terms are defined below, for drilling and completing all initial wells on execution of this Agreement. Notwithstanding, Atlas' payments for its share of the estimated Tangible Costs as that term is defined below of drilling and completing all initial wells as the Managing General Partner of the Developer shall be paid within five (5) business days of notice from Operator that the costs have been incurred. The Developer's payment shall be nonrefundable in all events in order to enable Operator to do the following: (i) commence site preparation for the initial wells; (ii) obtain suitable subcontractors for drilling and completing the wells at currently prevailing prices; and (iii) insure the availability of equipment and materials. 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 property acquisitions and 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 under the Code and its regulations. 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 and Tangible Costs for the well on execution of the applicable addendum pursuant to Section l(c) above. Notwithstanding, Atlas' payments for its share of the estimated Tangible Costs of drilling and completing all additional wells as the Managing General Partner of the Developer shall be paid within five (5) business days of notice from Operator that the costs have been incurred. The Developer's payment shall be nonrefundable in all events in order to enable Operator to do the following: (i) commence site preparation; (ii) obtain suitable subcontractors for drilling and completing the wells at currently prevailing prices; and (iii) insure the availability of equipment and materials. Developer shall pay, in proportion to the share of the Working Interest owned by the Developer in the wells, any extra costs incurred for each well pursuant to sub-section (a) above within ten (10) business days of its receipt of Operator's statement for the extra costs. (c) COMPLETION DETERMINATION. Operator shall determine whether or not to run the production casing for an attempted completion or to plug and abandon any well drilled under this Agreement. However, a well shall be completed only if Operator has made a good faith determination that there is a reasonable possibility of obtaining commercial quantities of oil and/or gas. 5 (d) DRY HOLE DETERMINATION. If Operator determines at any time during the drilling or attempted completion of any well under this Agreement, in accordance with the generally accepted and customary oil and gas field practices and techniques then prevailing in the geographic area of the Well Location that the well should not be completed, then it shall promptly and properly plug and abandon the well. (e) EXCESS FUNDS AND COST OVERRUNS-INTANGIBLE DRILLING COSTS. Any estimated Intangible Drilling Costs, which are the Intangible Drilling Costs set forth on the AFE, paid by Developer with respect to any well which exceed Operator's price specified in sub-section (a) above for the Intangible Drilling Costs of the well shall be retained by Operator and shall be applied to: (i) the Intangible Drilling Costs for an additional well or wells to be drilled on the Additional Well Locations; or (ii) any cost overruns owed by the Developer to Operator for Intangible Drilling Costs on one or more of the other wells on the Well Locations; in proportion to the share of the Working Interest owned by the Developer in the wells. Conversely, if Operator's price specified in sub-section (a) above for the Intangible Drilling Costs of any well exceeds the estimated Intangible Drilling Costs, which are the Intangible Drilling Costs set forth on the AFE, paid by Developer for the well, then: (i) Developer shall pay the additional price to Operator within five (5) business days after notice from Operator that the additional amount is due and owing; or (ii) Developer and Operator may agree to delete or reduce Developer's Working Interest in one or more wells which have not yet been spudded to provide funds to pay the additional amounts to Operator. If doing so results in any excess prepaid Intangible Drilling Costs, then these funds shall be applied to: (a) the Intangible Drilling Costs for an additional well or wells to be drilled on the Additional Well Locations; or (b) any cost overruns owed by Developer to Operator for Intangible Drilling Costs on one or more of the other wells on the Well Locations; in proportion to the share of the Working Interest owned by the Developer in the wells. The Exhibits to this Agreement with respect to the affected wells shall be amended as appropriate. (f) EXCESS FUNDS AND COST OVERRUNS - TANGIBLE COSTS. Any estimated Tangible Costs, which are the tangible costs set forth on the AFE, paid by Developer with respect to any well which exceed Operator's price specified in sub-section (a) above for the Tangible Costs of the well shall be retained by Operator and shall be applied to: (i) the Intangible Drilling Costs or Tangible Costs for an additional well or wells to be drilled on the Additional Well Locations; or (ii) any cost overruns owed by Developer to Operator for Intangible Drilling Costs or Tangible Costs on one or more of the other wells on the Well Locations; in proportion to the share of the Working Interest owned by the Developer in the wells. Conversely, if Operator's price specified in sub-section (a) above for the Tangible Costs of any well exceeds the estimated Tangible Costs, which are the tangible costs set forth on the AFE, paid by Developer for the well, then: 6 (i) Developer shall pay the additional price to Operator within ten (10) business days after notice from Operator that the additional price is due and owing; or (ii) Developer and Operator may agree to delete or reduce Developer's Working Interest in one or more wells which have not yet been spudded to provide funds to pay the additional price to Operator. If doing so results in any excess prepaid Tangible Costs, then these funds shall be applied to: (a) the Intangible Drilling Costs or Tangible Costs for an additional well or wells to be drilled on the Additional Well Locations; or (b) any cost overruns owed by Developer to Operator for Intangible Drilling Costs or Tangible Costs on one or more of the other wells on the Well Locations; in proportion to the share of the Working Interest owed by the Developer in the wells. The Exhibits to this Agreement with respect to the affected wells shall be amended as appropriate. 5. TITLE EXAMINATION OF WELL LOCATIONS, DEVELOPER'S ACCEPTANCE AND LIABILITY; ADDITIONAL WELL LOCATIONS. (a) TITLE EXAMINATION OF WELL LOCATIONS, DEVELOPER'S ACCEPTANCE AND LIABILITY. The Developer acknowledges that Operator has furnished Developer with the title opinions identified on Exhibit A, and other documents and information 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 Developer accepts the title to the Initial Well Locations and leased premises and acknowledges and agrees that, except for any loss, expense, cost, or liability caused by the breach of any of the warranties and representations made by the Operator in Section l(b), any loss, expense, cost or liability whatsoever caused by or related to any defect or failure of the title shall be the sole responsibility of and shall be borne entirely by the Developer. (b) ADDITIONAL WELL LOCATIONS. Before beginning drilling of any well on any Additional Well Location, Operator shall conduct, or cause to be conducted, a title examination of the Additional Well Location, in order to obtain appropriate abstracts, opinions and certificates and other information necessary to determine the adequacy of title to both the applicable Lease and the fee title of the lessor to the premises covered by the Lease. The results of the title examination and such other information as is necessary to determine the adequacy of title for drilling purposes shall be submitted to the Developer for its review and acceptance. No drilling on the Additional Well Locations shall begin until the 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 the title shall be the sole responsibility of and shall be borne entirely by the Developer, unless such loss, expense, cost, or liability was caused by the breach of any of the warranties and representations made by the Operator in Section l(b). 6. OPERATIONS SUBSEQUENT TO COMPLETION OF THE WELLS; FEE ADJUSTMENTS; EXTRAORDINARY COSTS; PIPELINES; PRICE DETERMINATIONS; PLUGGING AND ABANDONMENT. (a) OPERATIONS SUBSEQUENT TO COMPLETION OF THE WELLS. Beginning with the month in which a well drilled under this Agreement begins to produce, Operator shall be entitled to an operating fee of $285 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 the wells and related pipelines and facilities. The operating fees shall cover all normal, regularly recurring operating expenses for the production, delivery and sale of natural gas, including without limitation: (i) well tending, routine maintenance and adjustment; (ii) reading meters, recording production, pumping, maintaining appropriate books and records; 7 (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 the month subject to the 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, 2006 with respect to the partnership designated Atlas America Public #14-2004 L.P., and January 1, 2007 with respect to partnerships designated as Atlas America Public #14-2005(_____) L.P. 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, 2004, in the case of the first adjustment, and since the previous Adjustment Date, in the case of each subsequent adjustment. (c) EXTRAORDINARY COSTS. Without the prior written consent of the Developer, pursuant to a written estimate submitted by Operator, Operator shall not undertake any single project or incur any extraordinary cost with respect to any well being produced under this Agreement reasonably estimated to result in an expenditure of more than $5,000, unless the project or extraordinary cost is necessary for the following: (i) to safeguard persons or property; or (ii) to protect the well or related facilities in the event of a sudden emergency. In no event, however, shall the Developer be required to pay for any project or extraordinary cost arising from the negligence or misconduct of Operator, its agents, servants, employees, contractors, licensees, or invitees. All extraordinary costs incurred and the cost of projects undertaken with respect to a well being produced 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 project all or a portion of the estimated costs of the project 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 or its Affiliates and shall be maintained at their sole cost and expense. (e) PRICE DETERMINATIONS. Notwithstanding anything herein to the contrary, the Developer shall pay all costs in proportion to the share of the Working Interest owned by the Developer in the wells with respect to obtaining price determinations under and otherwise complying with the Natural Gas Policy Act of 1978 and the implementing state regulations. This responsibility shall include, without limitation, preparing, filing, and executing all applications, affidavits, interim collection notices, reports and other documents necessary or appropriate to obtain price certification, to effect sales of natural gas, or otherwise to comply with the Act and the implementing state regulations. 8 Operator agrees to furnish the information and render the assistance as the Developer may reasonably request in order to comply with the Act and the implementing state regulations without charge for services performed by its employees. (f) PLUGGING AND ABANDONMENT. The Developer shall have the right to direct Operator to plug and abandon any well that has been completed under this Agreement as a producer. In addition, Operator shall not plug and abandon any well that has been drilled and completed as a producer before 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 well should be plugged and abandoned and makes a written request to the Developer for authority to plug and abandon the well and the Developer fails to respond in writing to the request within forty-five (45) days following the date of the request, then the Developer shall be deemed to have consented to the plugging and abandonment of the well. All costs and expenses related to plugging and abandoning the wells which have been drilled and completed as producing wells shall be borne and paid by the Developer in proportion to the share of the Working Interest owned by the Developer in the wells. Also, at any time after one (1) year from the date each well drilled and completed is placed into production, Operator shall have the right to deduct each month from the proceeds of the sale of the production from the well up to $200, in proportion to the share of the Working Interest owned by the Developer in the wells, for the purpose of establishing a fund to cover the estimated costs of plugging and abandoning the well. All these 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 Developer's share of the costs of plugging and abandoning the well. 7. BILLING AND PAYMENT PROCEDURE WITH RESPECT TO OPERATION OF WELLS; DISBURSEMENTS; SEPARATE ACCOUNT FOR SALE PROCEEDS; RECORDS AND REPORTS; ADDITIONAL INFORMATION. (a) BILLING AND PAYMENT PROCEDURE WITH RESPECT TO OPERATION OF WELLS. Operator shall promptly and timely pay and discharge on behalf of the Developer, in proportion to the share of the Working Interest owned by the Developer in the wells the following: (i) all expenses and liabilities payable and incurred by reason of its operation of the wells in accordance with this Agreement, such as severance taxes, royalties, overriding royalties, operating fees, and pipeline gathering charges; and (ii) any third-party invoices rendered to Operator with respect to costs and expenses incurred in connection with the operation of the wells. Operator, however, shall not be required to pay and discharge any of the above costs and expenses which are being contested in good faith by Operator. Operator shall: (i) deduct the foregoing costs and expenses from the Developer's share of the proceeds of the oil and/or gas sold from the wells; and (ii) keep an accurate record of the Developer's account, showing expenses incurred and charges and credits made and received with respect to each well. If the proceeds are insufficient to pay the costs and expenses, then Operator shall promptly and timely pay and discharge the costs and expenses, 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 the costs and expenses. The invoice shall be accompanied by the form of statement specified in sub-section (b) below, and shall be paid by the Developer within ten (10) business days of its receipt. 9 (b) DISBURSEMENTS. Operator shall disburse to the Developer, on a monthly basis, the Developer's share of the proceeds received from the sale of oil and/or gas sold from the wells operated under this Agreement, less: (i) the amounts charged to the Developer under sub-section (a); and (ii) the amount, if any, withheld by Operator for future plugging costs pursuant to sub-section (f) of Section 6. Each disbursement made and/or invoice submitted 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 of the production; (ii) the total proceeds received from any sale of the production, and the Developer's share of the proceeds; (iii) the costs and expenses deducted from the proceeds and/or being billed to the Developer pursuant to sub-section (a) above; (iv) the amount withheld for future plugging costs; and (v) any other information as Developer may reasonably request, including without limitation copies of all third-party invoices listed on the statement for the period. (c) SEPARATE ACCOUNT FOR SALE PROCEEDS. Operator agrees to deposit all proceeds from the sale of oil and/or gas sold from the wells operated under this Agreement in a separate checking account maintained by Operator. This account shall be used solely for the purpose of collecting and disbursing funds constituting proceeds from the sale of production under this Agreement. (d) RECORDS AND REPORTS. In addition to the statements required under sub-section (b) above, Operator, within seventy-five (75) days after the completion of each well drilled, shall furnish the Developer with a detailed statement itemizing with respect to the well the total costs and charges under Section 4(a) and the Developer's share of the costs and charges, and any information as is necessary to enable the Developer: (i) to allocate any extra costs incurred with respect to the well between Tangible Costs and Intangible Drilling Costs; and (ii) to determine the amount of investment tax credit, if applicable. (e) ADDITIONAL INFORMATION. Operator shall promptly furnish the Developer with any additional information as it may reasonably request, including without limitation geological, technical, and financial information, in the form as may reasonably be requested, pertaining to any phase of the operations and activities governed by this Agreement. The Developer and its authorized employees, agents and consultants, including independent accountants shall, at Developer's sole cost and expense: (i) on at least ten (10) days' written notice have access during normal business hours to all of Operator's records pertaining to operations, including without limitation, the right to audit the books of account of Operator relating to all receipts, costs, charges, expenses and disbursements under this Agreement, including information regarding the separate account required under sub-section (c); and (ii) have access, at its sole risk, to any wells drilled by Operator under this Agreement at all times to inspect and observe any machinery, equipment and operations. 8. OPERATOR'S LIEN; RIGHT TO COLLECT FROM OIL OR GAS PURCHASER. (a) OPERATOR'S LIEN. To secure the payment of all sums due from Developer to Operator under the provisions of this Agreement the Developer grants Operator a first and preferred lien on and security interest in the following: 10 (i) the Developer's interest in the Leases covered by this Agreement; (ii) the Developer's interest in oil and gas produced under this Agreement and its proceeds from the sale of the oil and gas; and (iii) the Developer's interest in materials and equipment under this Agreement. (b) RIGHT TO COLLECT FROM OIL OR GAS PURCHASER. If the Developer fails to timely pay any amount owing under this Agreement by it to the Operator, then Operator, without prejudice to other existing remedies, may collect and retain from any purchaser or purchasers of oil or gas the Developer's share of the proceeds from the sale of the oil and gas until the amount owed by the Developer, plus twelve percent (12%) interest on a per annum basis, and any additional costs (including without limitation actual attorneys' fees and costs) resulting from the delinquency, has been paid. Each purchaser of oil or gas shall be entitled to rely on Operator's written statement concerning the amount of any default. 9. SUCCESSORS AND ASSIGNS; TRANSFERS; APPOINTMENT OF AGENT. (a) SUCCESSORS AND ASSIGNS. This Agreement shall be binding on and inure to the benefit of the undersigned parties and their respective successors and permitted assigns. However, without the prior written consent of the Developer, the Operator may not assign, transfer, pledge, mortgage, hypothecate, sell or otherwise dispose of any of its interest in this Agreement, or any of the rights or obligations under this Agreement. Notwithstanding, this consent shall not be required in connection with: (i) the assignment of work to be performed for Operator by subcontractors, it being understood and agreed, however, that any assignment to Operator's subcontractors shall not in any manner relieve or release Operator from any of its obligations and responsibilities under this Agreement; (ii) any lien, assignment, security interest, pledge or mortgage arising under Operator's present or future financing arrangements; or (iii) the liquidation, merger, consolidation, or other corporate reorganization or sale of substantially all of the assets of Operator. Further, in order to maintain uniformity of ownership in the wells, production, equipment, and leasehold interests covered by this Agreement, and notwithstanding any other 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 by this Agreement unless the disposition encompasses either: (i) the entire interest of the Developer in all wells, production, equipment and leasehold interests subject to this Agreement; or (ii) an equal undivided interest in all such wells, production, equipment, and leasehold interests. (b) TRANSFERS. Subject to the provisions of sub-section (a) above, any sale, encumbrance, transfer or other disposition made by the Developer of its interests in the wells, production, equipment, and/or leasehold interests covered by this Agreement shall be made: (i) expressly subject to this Agreement; (ii) without prejudice to the rights of the Operator; and (iii) in accordance with and subject to the provisions of the 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 the co-owners to appoint a single trustee or agent with full authority to do the following: 11 (i) receive notices, reports and distributions of the proceeds from production; (ii) approve expenditures; (iii) receive billings for and approve and pay all costs, expenses and liabilities incurred under this Agreement; (iv) exercise any rights granted to the co-owners under this Agreement; (v) grant any approvals or authorizations required or contemplated by this Agreement; (vi) sign, execute, certify, acknowledge, file and/or record any agreements, contracts, instruments, reports, or documents whatsoever in connection with this Agreement or the activities contemplated by this Agreement; and (vii) deal generally with, and with power to bind, the co-owners with respect to all activities and operations contemplated by this Agreement. However, all the co-owners shall continue to have the right to enter into and execute all contracts or agreements for their respective shares of the oil and gas produced from the wells drilled under this Agreement in accordance with sub-section (c) of Section 11. 10. OPERATOR'S INSURANCE; SUBCONTRACTORS' INSURANCE; OPERATOR'S LIABILITY. (a) OPERATOR'S INSURANCE. Operator shall obtain and maintain at its own expense so long as it is Operator under this Agreement all required Workmen's Compensation Insurance and comprehensive general public liability insurance in amounts and coverage not less than $1,000,000 per person per occurrence for personal injury or death and $1,000,000 for property damage per occurrence, which shall include coverage for blow-outs and total liability coverage of not less than $10,000,000. Subject to the above limits, the Operator's general public liability insurance shall be in all respects comparable to that generally maintained in the industry with respect to services of the type to be rendered and activities of the type to be conducted under this Agreement. Operator's general public liability insurance shall, if permitted by Operator's insurance carrier: (i) name the Developer as an additional insured party; and (ii) provide that at least thirty (30) days' prior notice of cancellation and any other adverse material change in the policy shall be given to the Developer. However, the Developer shall reimburse Operator for the additional cost, if any, of including it as an additional insured party under the Operator's insurance. Current copies of all policies or certificates of the Operator's insurance coverage shall be delivered to the Developer on request. It is understood and agreed that Operator's insurance coverage may not adequately protect the interests of the Developer and that the Developer shall carry at its expense the excess or additional general public liability, property damage, and other insurance, if any, as the Developer deems appropriate. (b) SUBCONTRACTORS' INSURANCE. Operator shall require all of its subcontractors to carry all required Workmen's Compensation Insurance and to maintain such other insurance, if any, as Operator in its discretion may require. (c) OPERATOR'S LIABILITY. Operator's liability to the Developer as Operator under this Agreement shall be limited to, and Operator shall indemnify the Developer and hold it harmless from, claims, penalties, liabilities, obligations, charges, losses, costs, damages, or expenses (including but not limited to reasonable attorneys' fees) relating to, caused by or arising out of: 12 (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. 11. INTERNAL REVENUE CODE ELECTION; RELATIONSHIP OF PARTIES; RIGHT TO TAKE PRODUCTION IN KIND. (a) INTERNAL REVENUE CODE ELECTION. With respect to this Agreement, each of the parties elects under Section 761(a) of the Internal Revenue Code of 1986, as amended, to be excluded from the provisions of Subchapter K of Chapter 1 of 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 by this Agreement is located contain, or may subsequently contain, a similar election, each of the parties agrees that the election shall be exercised. Beginning with the first taxable year of operations under this Agreement, each party agrees that the deemed election provided by Section 1.761-2(b)(2)(ii) of the Regulations under the Internal Revenue Code of 1986, as amended, will apply; and no party will file an application under Section 1.761-2 (b)(3)(i) and (ii) of the Regulations to revoke the election. Each party agrees to execute the documents and make the filings with the appropriate governmental authorities as may be necessary to effect the election. (b) RELATIONSHIP OF PARTIES. It is not the intention of the parties to create, nor shall this Agreement be construed as creating, a mining or other partnership or association or to render the parties liable as partners or joint venturers for any purpose. Operator shall be deemed to be an independent contractor and shall perform its obligations as set forth in this Agreement or as otherwise directed by the Developer. (c) RIGHT TO TAKE PRODUCTION IN KIND. Subject to the provisions of Section 8 above, the Developer shall have the exclusive right to sell or dispose of its proportionate share of all oil and gas produced from the wells to be drilled under this Agreement, exclusive of production: (i) that may be used in development and producing operations; (ii) unavoidably lost; and (iii) used to fulfill any free gas obligations under the terms of the applicable Lease or Leases. Operator shall not have any right to sell or otherwise dispose of the oil and gas. The Developer shall have the exclusive right to execute all contracts relating to the sale or disposition of its proportionate share of the production from the wells drilled under this Agreement. Developer shall have no interest in any gas supply agreements of Operator, except the right to receive Developer's share of the proceeds received from the sale of any gas or oil from wells developed under this Agreement. The Developer agrees to designate Operator or Operator's designated bank agent as the Developer's collection agent in any contracts. On request, Operator shall assist Developer in arranging the sale or disposition of Developer's oil and gas under this Agreement and shall promptly provide the Developer with all relevant information which comes to Operator's attention regarding opportunities for sale of production. If Developer fails to take in kind or separately dispose of its proportionate share of the oil and gas produced under this Agreement, then Operator shall have the right, subject to the revocation at will by the Developer, but not the obligation, to purchase the oil and gas or sell it to others at any time and from time to time, for the account of the Developer at the best price obtainable in the area for the production. Notwithstanding, Operator shall have no liability to Developer should Operator fail to market the production. Any 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 reasonable periods of time as are consistent with the minimum needs of the oil and gas industry under the particular circumstances, but in no event for a period in excess of one (1) year. 13 12. EFFECT OF FORCE MAJEURE; DEFINITION OF FORCE MAJEURE; LIMITATION. (a) EFFECT OF FORCE MAJEURE. If Operator is rendered unable, wholly or in part, by force majeure (as defined below) to carry out any of its obligations under this Agreement, including but not limited to beginning the drilling of one or more wells by the applicable times set forth in Section 2(b), or any Addendum to this Agreement, the obligations of the Operator, so far as it is affected by the force majeure, shall be suspended during but no longer than, the continuance of the force majeure. The Operator shall give to the Developer prompt written notice of the force majeure with reasonably full particulars concerning it. Operator shall use all reasonable diligence to remove the force majeure as quickly as possible to the extent the same is within reasonable control. (b) DEFINITION OF FORCE MAJEURE. The term "force majeure" shall mean an act of God, strike, lockout, or other industrial disturbance, act of the public enemy, war, blockade, public riot, lightning, fire, storm, flood, explosion, governmental restraint, unavailability of drilling rigs, equipment or materials, plant shut-downs, curtailments by purchasers and any other causes whether of the kind specifically enumerated above or otherwise, which directly preclude Operator's performance under this Agreement and is not reasonably within the control of the Operator including but not limited to, with respect to the Operator beginning the drilling of the wells subject to this Agreement by the applicable times set forth in Section 2(b), or any Addendum to this Agreement, decisions of third-party operators to delay drilling the wells, poor weather conditions, inability to obtain drilling permits, access right to the drilling site or title problems. (c) LIMITATION. The requirement that any force majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes, lockouts, or other labor difficulty affecting the Operator, contrary to its wishes. The method of handling these difficulties shall be entirely within the discretion of the Operator. 13. TERM. This Agreement shall become effective when executed by Operator and the Developer. Except as provided in sub-section (c) of Section 3, this Agreement shall continue and remain in full force and effect for the productive lives of the wells being operated under this Agreement. 14. GOVERNING LAW; INVALIDITY. (a) GOVERNING LAW. This Agreement shall be governed by, construed and interpreted in accordance with the laws of the Commonwealth of Pennsylvania. (b) INVALIDITY. The invalidity or unenforceability of any particular provision of this Agreement shall not affect the other provisions of this Agreement, and this Agreement shall be construed in all respects as if the invalid or unenforceable provision were omitted. 15. INTEGRATION; WRITTEN AMENDMENT. (a) INTEGRATION. This Agreement, including the Exhibits to this Agreement, constitutes and represents the entire understanding and agreement of the parties with respect to the subject matter of this Agreement and supersedes all prior negotiations, understandings, agreements, and representations relating to the subject matter of this Agreement. (b) WRITTEN AMENDMENT. No change, waiver, modification, or amendment of this Agreement shall be binding or of any effect unless in writing duly signed by the party against which the change, waiver, modification, or amendment is sought to be enforced. 16. WAIVER OF DEFAULT OR BREACH. No waiver by any party to any default of or breach by any other party under this Agreement shall operate as a waiver of any future default or breach, whether of like or different character or nature. 14 17. NOTICES. Unless otherwise provided in this Agreement, 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 #14-2004 L.P. [Atlas America Public #14-2005(____) L.P.] c/o Atlas Resources, Inc. 311 Rouser Road Moon Township, Pennsylvania 15108 Notices which are served by registered or certified mail on the parties in the manner provided in this Section shall be deemed sufficiently served or given for all purposes under this Agreement at the time the notice is mailed in any post office or branch post office regularly maintained by the United States Postal Service or any successor. All payments shall be hand-delivered or sent by United States mail, postage prepaid to the addresses set forth above until changed by certified or registered letter so addressed to the other party. 18. INTERPRETATION. The titles of the Sections in this Agreement are for convenience of reference only and shall not control or affect the meaning or construction of any of the terms and provisions of this Agreement. As used in this Agreement, the plural shall include the singular and the singular shall include the plural whenever appropriate. 19. COUNTERPARTS. The parties may execute this Agreement in any number of separate counterparts, each of which, when executed and delivered by the parties, shall have the force and effect of an original; but all such counterparts shall be deemed to constitute one and the same instrument. IN WITNESS WHEREOF, the parties hereto have duly executed this Agreement as of the day and year first above written. ATLAS RESOURCES, INC. By:____________________________________________ ATLAS AMERICA PUBLIC #14-2004 L.P. [ATLAS AMERICA PUBLIC #14-2005(____) L.P.] By its Managing General Partner: ATLAS RESOURCES, INC. By:____________________________________________ 15 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 Well Name, Twp. County, State ASSIGNMENT OF OIL AND GAS LEASE STATE OF _______________________________ COUNTY OF _____________________________ KNOW ALL MEN BY THESE PRESENTS: THAT the undersigned_________________________________________________ (hereinafter called "Assignor"), for and in consideration of One Dollar and other valuable consideration ($1.00 ovc), the receipt whereof is hereby acknowledged, does hereby sell, assign, transfer and set over unto____________________________________________________ (hereinafter called "Assignee"), an undivided _____________________________ in, and to, the oil and gas lease described as follows: together with the rights incident thereto and the personal property thereto, appurtenant thereto, or used, or obtained, in connection therewith. And for the same consideration, the assignor covenants with the said assignee his or its heirs, successors, or assigns that assignor is the lawful owner of said lease and rights and interest thereunder and of the personal property thereon or used in connection therewith; that the undersigned has good right and authority to sell and convey the same, and that said rights, interest and property are free and clear from all liens and encumbrances, and that all rentals and royalties due and payable thereunder have been duly paid. In Witness Whereof, the undersigned owner ______ and assignor ______ ha___ signed and sealed this instrument the ______ day of _______________, 200___. Signed and acknowledged in the presence of _________________________________ __________________________________________ _________________________________ __________________________________________ _________________________________ Exhibit B (Page 1) ACKNOWLEDGMENT BY INDIVIDUAL STATE OF -------------------------- BEFORE ME, a Notary Public, in and for said COUNTY OF ------------------------ County and State, on this day personally appeared who acknowledged to me that ____ he ____ did sign the foregoing instrument and that the same is _____________ free act and deed. In testimony whereof, I have hereunto set my hand and official seal, at_____________________________, this ______ day of _______________, A.D., 200___. _____________________________ Notary Public CORPORATION ACKNOWLEDGMENT STATE OF -------------------------- BEFORE ME, a Notary Public, in and for said COUNTY OF ------------------------ County and State, on this day personally appeared known to me to be the person and officer whose name is subscribed to the foregoing instrument and acknowledged that the same was the act of the said ______________________________________________, a corporation, and that he executed the same as the act of such corporation for the purposes and consideration therein expressed, and in the capacity therein stated. In testimony whereof, I have hereunto set my hand and official seal, at_____________________________, this ______ day of _______________, A.D., 200___. _____________________________ Notary Public This instrument prepared by: Atlas Resources, Inc. 311 Rouser Road P.O. Box 611 Moon Township, PA 15108 Exhibit B (Page 2) ADDENDUM NO. __________ TO DRILLING AND OPERATING AGREEMENT DATED ___________________ , 200___ THIS ADDENDUM NO. __________ made and entered into this ______ day of ________________, 200___, by and between ATLAS RESOURCES, INC., a Pennsylvania corporation (hereinafter referred to as "Operator"), and ATLAS AMERICA PUBLIC #14-2004 L.P. [ATLAS AMERICA PUBLIC #14-2005(____) L.P.], a Delaware limited partnership, (hereinafter referred to as the Developer). WITNESSETH THAT: WHEREAS, Operator and the Developer have entered into a Drilling and Operating Agreement dated ___________________, 200___, (the "Agreement"), which relates to the drilling and operating of ________________ (______)wells on the ________________ (______) Initial Well Locations identified on the maps attached as Exhibits A-l through A-______ to the Agreement, and provides for the development on the terms and conditions set forth in the Agreement of Additional Well Locations as the parties may from time to time designate; and WHEREAS, pursuant to Section l(c) of the Agreement, Operator and Developer presently desire to designate ________________ Additional Well Locations described below to be developed in accordance with the terms and conditions of the Agreement. NOW, THEREFORE, in consideration of the mutual covenants contained in this Addendum and intending to be legally bound, the parties agree as follows: 1. Pursuant to Section l(c) of the Agreement, the Developer hereby authorizes Operator to drill, complete (or plug) and operate, on the terms and conditions set forth in the Agreement and this Addendum No.__________, ________________ additional wells on the ________________ Additional Well Locations described on Exhibit A to this Addendum and on the maps attached to this Addendum as Exhibits A-______ through A-______. 2. Operator, as Developer's independent contractor, agrees to drill, complete (or plug) and operate the additional wells on the Additional Well Locations in accordance with the terms and conditions of the Agreement and further agrees to begin drilling the first additional well within thirty (30) days after the date of this Addendum and to begin drilling all the additional wells on or before March ___, 2005 [March ___, 2006]. 3. Developer acknowledges that: (a) Operator has furnished Developer with the title opinions identified on Exhibit A to this Addendum; and (b) such other documents and information which Developer or its counsel has requested in order to determine the adequacy of the title to the above Additional Well Locations. The Developer accepts the title to the Additional Well Locations and leased premises in accordance with the provisions of Section 5 of the Agreement. 4. The drilling and operation of the additional wells on the Additional Well Locations shall be in accordance with and subject to the terms and conditions set forth in the Agreement as supplemented by this Addendum No. __________ and except as previously supplemented, all terms and conditions of the Agreement shall remain in full force and effect as originally written. 5. This Addendum No. __________ shall be legally binding on, and shall inure to the benefit of, the parties and their respective successors and permitted assigns. Exhibit C (Page 1) WITNESS the due execution of this Addendum on the day and year first above written. ATLAS RESOURCES, INC. By________________________________________ ATLAS AMERICA PUBLIC #14-2004 L.P. [ATLAS AMERICA PUBLIC #14-2005(____) L.P.] By its Managing General Partner: ATLAS RESOURCES, INC. By________________________________________ 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 set forth below. SPECIAL SUITABILITY REQUIREMENTS IF YOU ARE BUYING LIMITED PARTNER UNITS IN CALIFORNIA, MICHIGAN, NEW HAMPSHIRE, NORTH CAROLINA, OHIO, AND PENNSYLVANIA. I. If you are a resident of CALIFORNIA and you purchase limited partners units, then you must meet any one of the following special suitability requirements: o a net worth of not less than $250,000, exclusive of home, home furnishings and automobiles, and expect to have gross income in the current year of $65,000 or more; or o a net worth of not less than $500,000, exclusive of home, home furnishings and automobiles; or o a net worth of not less than $1 million; or o expected gross income in the current tax year of not less than $200,000. II. If you are a resident of MICHIGAN OR NORTH CAROLINA and you purchase limited partner units, then you must meet any one of the following special suitability requirements: o a net worth of not less than $225,000, exclusive of home, home furnishings and automobiles; or o a net worth of not less than $60,000, exclusive of home, home furnishings and automobiles, and estimated CURRENT 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. III. 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, home furnishings and automobiles. IV. If you are a resident of NEW HAMPSHIRE and you purchase limited partner units, then you must meet any one of the following: o a net worth of not less than $250,000, exclusive of home, home furnishings, and automobiles, or o a net worth of not less than $125,000, exclusive of home, home furnishings, and automobiles, and $50,000 of taxable income. SPECIAL SUITABILITY REQUIREMENTS IF YOU ARE BUYING INVESTOR GENERAL PARTNER UNITS IN ALABAMA, ARIZONA, ARKANSAS, 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. I. If you are a resident of CALIFORNIA and you purchase investor general partner units, then you must meet any one of the following special suitability requirements: o a net worth of not less than $250,000, exclusive of home, home furnishings and automobiles, and expect to have annual gross income in the current year of $120,000 or more; or o a net worth of not less than $500,000, exclusive of home, home furnishings and automobiles; or o a net worth of not less than $1 million; or o expected gross income in the current year of not less than $200,000. 2 II. If you are a resident of any of the following states: o ALABAMA; o MINNESOTA; o PENNSYLVANIA; o ARKANSAS; o NORTH CAROLINA; o TENNESSEE; o MAINE; o OHIO; o TEXAS; OR o MASSACHUSETTS; o OKLAHOMA; o WASHINGTON. and you purchase investor general partner units, then you must meet any one of the following special suitability requirements: o 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 o an individual or joint net worth with your spouse in excess of $1 million, inclusive of home, home furnishings and automobiles; or o an individual or joint net worth with your spouse in excess of $500,000, exclusive of home, home furnishings and automobiles; or o 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. III. If you are a resident of any of the following states: o ARIZONA; o KENTUCKY; o NEW MEXICO; o INDIANA; o MICHIGAN; o OREGON; o IOWA; o MISSISSIPPI; o SOUTH DAKOTA; OR o KANSAS; o MISSOURI; o VERMONT; and you purchase investor general partner units, then you must meet any one of the following special suitability requirements: o 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 o an individual or joint net worth with your spouse in excess of $1 million, inclusive of home, home furnishings and automobiles; or o an individual or joint net worth with your spouse in excess of $500,000, exclusive of home, home furnishings and automobiles; or o 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. IV. In addition, if you are a resident of any of the following states: o IOWA; o OHIO; OR o MICHIGAN; o PENNSYLVANIA; 3 then you must not make an investment in the partnership in excess of 10% of your net worth, exclusive of home, furnishings and automobiles. IV. If you are a resident of NEW HAMPSHIRE and you purchase investor general partner units, then you must meet any one of the following special suitability requirements: o a net worth of not less than $250,000, exclusive of home, home furnishings, and automobiles, or o have a net worth of not less than $125,000, exclusive of home, home furnishings, and automobiles, and $50,000 of taxable income. SPECIAL REPRESENTATIONS FOR SUBSCRIBERS OF CALIFORNIA, MISSOURI, NORTH CAROLINA AND PENNSYLVANIA. I. If a resident of CALIFORNIA, I am aware that: IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY, OR ANY INTEREST THEREIN, OR TO RECEIVE ANY CONSIDERATION THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF THE COMMISSIONER OF CORPORATIONS OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED IN THE COMMISSIONER'S RULES. As a condition of qualification of the units for sale in the State of California, the following rule is hereby delivered to each California purchaser. CALIFORNIA ADMINISTRATIVE CODE, TITLE 10, CH. 3, RULE 260.141.11. RESTRICTION ON TRANSFER. (a) The issuer of any security upon which a restriction on transfer has been imposed pursuant to 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; 4 (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 subdivision (f) of Section 25102; provided that any such transfer is on the condition that any certificate evidencing the security issued to such transferee shall contain the legend required by this section. (c) The certificates representing all such securities subject to such a restriction on transfer, whether upon initial issuance or upon any transfer thereof, shall bear on their face a legend, prominently stamped or printed thereon in capital letters of not less than 10-point size, reading as follows: "IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY, OR ANY INTEREST THEREIN, OR TO RECEIVE ANY CONSIDERATION THEREFOR, WITHOUT THE PRIOR WRITTEN CONSENT OF THE COMMISSIONER OF CORPORATIONS OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED IN THE COMMISSIONER'S RULES." II. If a resident of 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)). III. 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. IV. PENNSYLVANIA INVESTORS: Because the minimum closing amount is less than 10% of the maximum closing amount allowed to a partnership in this offering, you are cautioned to carefully evaluate the partnership's ability to fully accomplish its stated objectives and inquire as to the current dollar volume of partnership subscriptions. 5
TABLE OF CONTENTS =================================================================== ========================================================== Page Summary of the Offering...........................................1 Risk Factors......................................................8 Additional Information...........................................17 Forward Looking Statements and Associated Risks.........................................................17 Investment Objectives............................................18 Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners.........................19 Capitalization and Source of Funds and Use of Proceeds......................................................21 Compensation.....................................................25 Terms of the Offering............................................31 Prior Activities.................................................38 Management.......................................................49 Management's Discussion and Analysis of Financial Condition, Results of Operations, Liquidity and Capital Resources........55 Proposed Activities..............................................57 Competition, Markets and Regulation..............................70 ATLAS AMERICA Participation in Costs and Revenues..............................74 Conflicts of Interest............................................81 PUBLIC #14-2004 PROGRAM Fiduciary Responsibility of the Managing General Partner...............................................91 Material Federal Income Tax Consequences.........................93 Summary of Partnership Agreement................................111 Summary of Drilling and Operating Agreement.....................113 Reports to Investors............................................114 Presentment Feature.............................................115 Transferability of Units........................................117 Plan of Distribution............................................118 Sales Material..................................................121 Legal Opinions..................................................122 Experts.........................................................122 ---------------- Litigation......................................................123 PROSPECTUS Financial Information Concerning the Managing General Partner ---------------- and Atlas America Public #14-2004 L.P........................123 EXHIBIT (A) - Form of Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #14-2004 L.P. [Form of Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #14-2005(_____) L.P.] EXHIBIT (I-A) - Form of Managing General Partner Signature Page EXHIBIT (I-B) - Form of Subscription Agreement EXHIBIT (II) - Form of Drilling and Operating Agreement for Atlas America Public #14-2004 L.P. [Atlas America Public #14-2005(_____) L.P.] EXHIBIT (B) - Special Suitability Requirements and Disclosures to Investors No one has been authorized to give any information or make any Until December 31, 2005, all dealers that effect representations other than those contained in this prospectus in transactions in these securities, whether or not connection with this offering. If given or made, you should not participating in this offering, may be required to rely on such information or representations as having been deliver a prospectus. This is in addition to the dealers' authorized by the managing general partner. The delivery of this obligation to deliver a prospectus when acting as prospectus does not imply that its information is correct as of any underwriters and with respect to their unsold allotments time after its date. This prospectus is not an offer to sell these or subscriptions. securities in any state to any person where the offer and sale is not permitted. =================================================================== ==========================================================
PART II INFORMATION NOT REQUIRED IN PROSPECTUS ITEM 13. 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 Fees and Expenses.......................................................................$40,000* Legal Fees (including Blue Sky) and Expenses.......................................................125,000* Printing.......................................................................................... 300,000* SEC Registration Fee................................................................................15,838 Blue Sky Filing Fees (excluding legal fees)........................................................212,000* NASD Filing Fee.....................................................................................13,000 Miscellaneous....................................................................................1,413,565* --------- Total.....................................................$2,119,403* ==========
- --------------- *Estimated ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS. Title 8, Section 141 of the Delaware Code 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: o they determined in good faith that the course of conduct which caused the loss or liability was in the best interest of the Partnership; o they were acting on behalf of or performing services for the Partnership; and o 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 15. 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. ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES. (a) 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. 1 1(c) Proposed form of Selected Investment Advisor Agreement 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 #14-2004 L.P. 4(b) Form of Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #14-2004 L.P. [Form of Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #14-2005(___) L.P.] (See Exhibit (A) to Prospectus) 5 Opinion of Kunzman & Bollinger, Inc. as to the legality of the Units 8 Opinion of Kunzman & Bollinger, Inc. as to tax matters 10(a) Escrow Agreement for Atlas America Public #14-2004 L.P. 10(b) Proposed Form of Drilling and Operating Agreement [Atlas America Public #14-2004(____) L.P.] (See Exhibit (II) to the Form of Limited Partnership Agreement, Exhibit (A) to Prospectus) 10(c) Gas Purchase Agreement dated March 31, 1999 between Northeast Ohio Gas Marketing, Inc., and Atlas Energy Group, Inc., Atlas Resources, Inc., and Resource Energy, Inc. 10(d) Guaranty dated August 12, 2003 between First Energy Corp. and Atlas Resources, Inc. to Gas Purchase Agreement dated March 31, 1999 between Northeast Ohio Gas Marketing, Inc., and Atlas Energy Group, Inc., Atlas Resources, Inc., and Resource Energy, Inc. 10(e) Master Natural Gas Gathering Agreement dated February 2, 2000 among Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, Inc., and Viking Resources Corporation 10(f) Omnibus Agreement dated February 2, 2000 among Atlas America, Inc., Resource Energy, Inc., and Viking Resources Corporation, and Atlas Pipeline Operating Partnership, L.P., and Atlas Pipeline Partners, L.P. 10(g) Natural Gas Gathering Agreement dated January 1, 2002 among Atlas Pipeline Partners, L.P., and Atlas Pipeline Operating Partnership, L.P. and Atlas Resources, Inc., and Atlas Energy Group, Inc. and Atlas Noble Corporation, and Resource Energy Inc., and Viking Resources Corporation 10(h) Base Contract for Sale and Purchase of Natural Gas dated November 13, 2002 Between UGI Energy Services, Inc. and Viking Resources Corp. 23(a) Consent of Independent Certified Public Accountants 23(b)* Consent of United Energy Development Consultants, Inc. 23(c) Consent of Kunzman & Bollinger, Inc. (See Exhibits 5 and 8) 24 Power of Attorney - ------------ * To Be Filed By Amendment. (b) Financial Statement Schedules All financial statement schedules are omitted because the information is not required, is not material or is otherwise included in the financial statements or related notes thereto. 2 ITEM 17. UNDERTAKINGS. (a) 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: (i) To include any Prospectus required by Section 10(a)(3) of the Securities Act of 1933. (ii) To reflect in the Prospectus any facts or events arising after the effective date of the Registration Statement (or the most recent Post-Effective Amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the Registration Statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of the securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than a 20% change in the maximum aggregate offering price set forth in the "Calculation of Registration Fee" table in the effective registration statement. (iii) To 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. Provided, however, that paragraphs (a)(1)(i) and (a)(1)(ii) do not apply if the registration statement is on Form S-3 or Form S-8 and the information required to be included in a post-effective amendment by those paragraphs is contained in periodic reports filed by the registrant pursuant to section 13 or section 15(d) of the Securities Exchange Act of 1934 that are incorporated by reference 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. (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. The undersigned Registrant hereby undertakes to provide at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser. Because acceleration is requested of the effective date of the Registration Statement pursuant to Rule 461 under the Securities Act, and: (1) provisions or arrangements exist whereby the Registrant may indemnify a director, officer or controlling person of the Registrant against liabilities arising under the Securities Act, or (2) the underwriting agreement contains a provision whereby the Registrant indemnifies the underwriter or controlling persons of the underwriter against such liabilities and a director, officer or controlling person of the Registrant is such an underwriter or controlling person thereof or a member of any firm which is such an underwriter, and (3) the benefits of such indemnification are not waived by such persons, the Registrant makes the following undertaking: Insofar as indemnification for liabilities arising under the Securities Act of 1933 (the "Act") may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue. The undersigned Registrant hereby undertakes that: o For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective. o For purposes of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. 3 SIGNATURES Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Moon Township, Pennsylvania on June 30, 2004. ATLAS AMERICA PUBLIC #14-2004 PROGRAM (Registrant) By: Atlas Resources, Inc., Managing General Partner Jack L. Hollander, pursuant By: /s/ Jack L. Hollander to the Registration Statement, has ------------------------------------ been granted Power of Attorney and is Jack L. Hollander, Senior Vice signing on behalf of the names shown President - Direct Participation below, in the capacities indicated. Programs 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 - --------- ----- ---- Freddie M. Kotek President, Chief Executive Officer and Chairman of the Board of Directors June 30, 2004 Frank P. Carolas Executive Vice President - Land and Geology and a Director Executive Vice June 30, 2004 Jeffrey C. Simmons President - Operations and a Director Senior Vice President, Chief Financial June 30, 2004 Nancy J. McGurk Officer and Chief Accounting Officer June 30, 2004
As filed with the Securities and Exchange Commission on June 30, 2004 ================================================================================ SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 --------------------------------- EXHIBITS TO FORM S-1 REGISTRATION STATEMENT Under THE SECURITIES ACT OF 1933 --------------------------------- ATLAS AMERICA PUBLIC #14-2004 PROGRAM (Exact name of Registrant as Specified in its Charter) --------------------------------- JACK L. HOLLANDER, SENIOR VICE PRESIDENT - DIRECT PARTICIPATION PROGRAMS 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. JACK L. HOLLANDER KUNZMAN & BOLLINGER, INC. ATLAS RESOURCES, INC. 5100 N. BROOKLINE, SUITE 600 311 ROUSER ROAD OKLAHOMA CITY, OKLAHOMA 73112 MOON TOWNSHIP, PENNSYLVANIA 15108 ================================================================================ EXHIBIT INDEX Exhibit No. Description - ----------- ----------- 1(a) Proposed form of Dealer-Manager Agreement with Anthem Securities, Inc. 1(b)* Proposed form of Dealer-Manager Agreement with Bryan Funding, Inc. 1(c) Proposed form of Selected Investment Advisor Agreement 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 #14-2004 L.P. 4(b) Form of Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #14-2004 L.P. [Form of Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #14-2005(___) L.P.] (See Exhibit (A) to Prospectus) 5 Opinion of Kunzman & Bollinger, Inc. as to the legality of the Units 8 Opinion of Kunzman & Bollinger, Inc. as to tax matters 10(a) Escrow Agreement for Atlas America Public #14-2004 L.P. 10(b) Proposed form of Drilling and Operating Agreement [Atlas America Public #14-2005(___) L.P.] (See Exhibit (II) to the Form of Limited Partnership Agreement, Exhibit (A) to Prospectus) 10(c) Gas Purchase Agreement dated March 31, 1999 between Northeast Ohio Gas Marketing, Inc., and Atlas Energy Group, Inc., Atlas Resources, Inc., and Resource Energy, Inc. 10(d) Guaranty dated August 12, 2003 between First Energy Corp. and Atlas Resources, Inc. to Gas Purchase Agreement dated March 31, 1999 between Northeast Ohio Gas Marketing, Inc., and Atlas Energy Group, Inc., Atlas Resources, Inc., and Resource Energy, Inc. 10(e) Master Natural Gas Gathering Agreement dated February 2, 2000 among Atlas Pipeline Partners, L.P. and Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, Inc., and Viking Resources Corporation 10(f) Omnibus Agreement dated February 2, 2000 among Atlas America, Inc., Resource Energy, Inc., and Viking Resources Corporation, and Atlas Pipeline Operating Partnership, L.P., and Atlas Pipeline Partners, L.P. 10(g) Natural Gas Gathering Agreement dated January 1, 2002 among Atlas Pipeline Partners, L.P., and Atlas Pipeline Operating Partnership, L.P. and Atlas Resources, Inc., and Atlas Energy Group, Inc. and Atlas Noble Corporation, and Resource Energy Inc., and Viking Resources Corporation 10(h) Base Contract for Sale and Purchase of Natural Gas dated November 13, 2002 Between UGI Energy Services, Inc. and Viking Resources Corp. 23(a) Consent of Independent Certified Public Accountants 23(b)* Consent of United Energy Development Consultants, Inc. 23(c) Consent of Kunzman & Bollinger, Inc. (See Exhibits 5 and 8) 24 Power of Attorney - ----------------- *To be filed by Amendment. EX-1 2 ex-1a.txt EXHIBIT 1(A) ATLAS AMERICA PUBLIC #14-2004 PROGRAM DEALER-MANAGER AGREEMENT WITH ANTHEM SECURITIES, INC. ANTHEM SECURITIES, INC. DEALER-MANAGER AGREEMENT TABLE OF CONTENTS
PAGE 1. Description of Program and Units......................................................................1 2. Representations, Warranties and Agreements of the Managing General Partner............................2 3. Grant of Authority to the Dealer-Manager..............................................................3 4. Compensation and Fees.................................................................................3 5. Covenants of the Managing General Partner.............................................................6 6. Representations and Warranties of the Dealer-Manager..................................................6 7. State Securities Registration........................................................................11 8. Expense of Sale......................................................................................12 9. Conditions of the Dealer-Manager's Duties............................................................12 10. Conditions of the Managing General Partner's Duties..................................................12 11. Indemnification......................................................................................12 12. Representations and Agreements to Survive Delivery...................................................13 13. Termination..........................................................................................13 14. Notices..............................................................................................14 15. Format of Checks/Escrow Agent........................................................................14 16. Transmittal Procedures...............................................................................14 17. Parties..............................................................................................15 18. Relationship.........................................................................................15 19. Effective Date.......................................................................................15 20. Entire Agreement, Waiver.............................................................................15 21. Governing Law........................................................................................16 22. Complaints...........................................................................................16 23. Privacy..............................................................................................16 24. Anti-Money Laundering Provision......................................................................16 25. Acceptance...........................................................................................16
Exhibit A - Form of Escrow Agreement Exhibit B - Selling Agent Agreement i Anthem Securities, Inc. Dealer-Manager Agreement ANTHEM SECURITIES, INC. DEALER-MANAGER AGREEMENT (Best Efforts) Anthem Securities, Inc. P.O. Box 926 Moon Township, Pennsylvania 15108-0926 RE: ATLAS AMERICA PUBLIC #14-2004 PROGRAM ------------------------------------- Gentlemen: The undersigned, Atlas Resources, Inc., which is referred to as the "Managing General Partner," on behalf of Atlas America Public #14-2004 Program, which is referred to as the "Program," is a series of up to three limited partnerships organized or to be organized under the laws of Delaware as described below. These limited partnerships are sometimes referred to in this Agreement in the singular as a "Partnership" or in the plural as "Partnerships." The Managing General Partner on behalf of the Partnerships hereby confirms its agreement with you, as Dealer-Manager, as follows: 1. DESCRIPTION OF PROGRAM AND UNITS. (a) The Managing General Partner, a Pennsylvania corporation, proposes to be the sole managing general partner of up to three limited partnerships formed or to be formed under the Delaware Revised Uniform Limited Partnership Act. The Partnerships will be named as follows: (i) Atlas America Public #14-2004 L.P.; (ii) Atlas America Public #14-2005(A) L.P.; and (iii) Atlas America Public #14-2005(B) L.P. On behalf of the Program and the Partnerships, a Registration Statement on Form S-1 (Registration No. ____________) relating to the offer and sale of the limited partner and investor general partner interests in the Partnerships, which are referred to as the "Units," was filed on ______________, 2004 with the Securities and Exchange Commission (the "Commission") under the Securities Act of 1933, which is referred to as the "Act." The Registration Statement has been declared effective by the Commission and the Partnerships and the Units are described in the Prospectus (the "Prospectus") that forms a part of the Registration Statement. As used in this Agreement, the terms "Prospectus" and "Registration Statement" refer solely to the Prospectus and Registration Statement, as amended, described above, except that: (i) from and after the date on which any post-effective amendment to the Registration Statement is declared effective by the Commission, the term "Registration Statement" shall refer to the Registration Statement as amended by that post-effective amendment, and the term "Prospectus" shall refer to the Prospectus then forming a part of the Registration Statement; and Anthem Securities, Inc. 1 Dealer-Manager Agreement (ii) if the Prospectus filed by the Managing General Partner pursuant to Rule 424(b) or (c) promulgated by the Commission under the Act differs from the Prospectus on file with the Commission at the time the Registration Statement or any post-effective amendment thereto shall have become effective, the term "Prospectus" shall refer to the Prospectus filed pursuant thereto from and after the date on which it was filed. Terms defined in the Prospectus and not otherwise defined in this Agreement shall have the meanings set forth in the Prospectus. (b) The Units will be sold at a price of $10,000 per Unit subject to the discounts set forth in Section 4(c) of this Agreement for certain investors. Subject to the receipt and acceptance by the Managing General Partner of the minimum subscription proceeds of $2,000,000 in a Partnership by its Offering Termination Date for each Partnership as described in the Prospectus (the "Offering Termination Date"), the Managing General Partner may break escrow and use the subscription proceeds for the Partnership's drilling activities, which is referred to as the "Initial Closing Date." The subscription period for each Partnership will be as described in the Prospectus. However, the offering of Atlas America Public #14-2004 L.P. may not extend beyond December 31, 2004, the offering of Atlas America Public #14-2005(A) L.P. may not extend beyond May 31, 2004, and the offering of Atlas America Public #14-2005(B) L.P. may not extend beyond December 31, 2005. Also, the maximum subscription proceeds of all the Partnerships, in the aggregate, must not exceed the registered amount of $125 million. The Managing General Partner will notify you and the "Selling Agents," as defined below, of the Initial Closing Date and Offering Termination Date for each Partnership. 2. REPRESENTATIONS, WARRANTIES AND AGREEMENTS OF THE MANAGING GENERAL PARTNER. The Managing General Partner represents and warrants to and agrees with you that: (a) The Partnerships composing the Program have a currently effective Registration Statement on Form S-1, including a final Prospectus, for the registration of the Units under the Act as described in Section 1 of this Agreement. (b) The Managing General Partner shall provide to you for delivery to all offerees and purchasers and their representatives the information and documents that the Managing General Partner deems appropriate to comply with the Act and applicable state securities acts, which are referred to as the "Blue Sky" laws. (c) The Units when issued will be duly authorized and validly issued as set forth in the Agreement of Limited Partnership of each Partnership, which is referred to as the "Partnership Agreement," the form of which is included as Exhibit (A) to the Prospectus, and subject only to the rights and obligations set forth in the Partnership Agreement or imposed by the laws of the state of formation of each Partnership or of any jurisdiction to the laws of which each Partnership is subject. (d) Each Partnership was or will be duly formed under the laws of the State of Delaware and once formed will be validly existing as a limited partnership in good standing under the laws of Delaware with full power and authority to own its properties and conduct its business as described in the Prospectus. Each Partnership will be qualified to do business as a limited partnership or similar entity offering limited liability in those jurisdictions where the Managing General Partner deems the qualification necessary to assure limited liability of the limited partners. Anthem Securities, Inc. 2 Dealer-Manager Agreement This Agreement, when executed by you, will be a valid and binding agreement of each Partnership and the Managing General Partner, duly authorized, executed and delivered by them and enforceable in accordance with its terms except as may be limited by the effect of bankruptcy, insolvency, moratorium, preferential or fraudulent conveyance or other laws or equitable principles relating to or affecting the rights of creditors generally, general principles of equity, and by public policy relating to claims for indemnification for securities laws violations. (e) The Prospectus, as supplemented or amended, does not contain an untrue statement of a material fact or omit to state any material fact necessary in order to make the statements in the Prospectus, in the light of the circumstances under which they are made, not misleading. 3. GRANT OF AUTHORITY TO THE DEALER-MANAGER. (a) Based on the representations and warranties contained in this Agreement, and subject to the terms and conditions set forth in this Agreement, the Managing General Partner appoints you as the Dealer-Manager for the Partnerships and gives you the exclusive right to solicit subscriptions for the Units on a "best efforts" basis in all states other than: (i) Minnesota; and (ii) New Hampshire during the offering period as described in the Prospectus. (b) In all states other than Minnesota and New Hampshire you agree to use your best efforts to effect sales of the Units and to form and manage a selling group composed of soliciting broker/dealers, which are referred to as the "Selling Agents," each of which shall be a member of the National Association of Securities Dealers, Inc., which is referred to as the "NASD," and shall enter into a "Selling Agent Agreement" in substantially the form attached to this Agreement as Exhibit "B." (c) The Managing General Partner shall have three business days after the receipt of an executed Selling Agent Agreement to refuse that Selling Agent's participation. 4. COMPENSATION AND FEES. (a) As Dealer-Manager you shall receive from the Managing General Partner the following compensation, based on each Unit sold to investors in a Partnership who are situated and/or residents in states other than Minnesota and New Hampshire and whose subscriptions for Units are accepted by the Managing General Partner: (i) a 2.5% Dealer-Manager fee; (ii) a 7% Sales Commission; (iii) a .5% accountable Reimbursement for Permissible Non-Cash Compensation which, under Rule 2810 of the NASD Conduct Rules, is composed of the following: (A) training and education meetings for associated persons of the Selling Agents meeting the requirements set forth in Section 4(b), below; (B) gifts that do not exceed $100 per year and is not preconditioned on the achievement of a sales target; Anthem Securities, Inc. 3 Dealer-Manager Agreement (C) an occasional meal, a ticket to a sporting event or the theater, or comparable entertainment which is neither so frequent nor so extensive as to raise any question of propriety and is not preconditioned on achievement of a sales target; and (D) contributions to a non-cash compensation arrangement between a Selling Agent and its associated persons, provided that neither we nor you directly or indirectly participate in the Selling Agent's organization of a the permissible non-cash compensation arrangement; and (iv) an up to .5% reimbursement of the Selling Agents' bona fide accountable due diligence expenses. (b) All of the up to .5% reimbursement of the Selling Agents' bona fide accountable due diligence expenses shall be reallowed to the Selling Agents, and all or a portion of the 7% Sales Commission and the .5% Reimbursement for Permissible Non-Cash Compensation shall be reallowed to the Selling Agents as described in the Selling Agent Agreement with each Selling Agent. Most, if not all, of the remaining balance of the 2.5% Dealer-Manager fee shall be reallowed to the wholesalers as wholesaling fees for subscriptions obtained through their efforts less any reimbursements made by the Managing General Partner or the Partnership for expenses which are received by the wholesalers in connection with the Program or expenses which are owed by the wholesalers to the Managing General Partner or the Partnership in connection with the Program and any salaries for the wholesalers in connection with the Program. You, as Dealer-Manager, shall retain any Dealer-Manager fee not reallowed to the wholesalers, which may be used for such items as legal fees associated with the underwriting and salaries of dual employees of you and the Managing General Partner which are required to be included in underwriting compensation under NASD Conduct Rule 2810 as determined jointly by the Managing General Partner and you. You shall retain: (i) any of the 7% Sales Commission not reallowed to the Selling Agents; (ii) any of the .5% accountable Reimbursement for Permissible Non-Cash Compensation not paid or reimbursed to the Selling Agents by you or the Managing General Partner; and (iii) any of the remaining balance of the 2.5% Dealer-Manager fee not reallowed to the wholesalers pursuant to the first paragraph of this Section 4(b). You are responsible for ensuring that all non-cash compensation arrangements comply with NASD Conduct Rule 2810. For example, payments or reimbursements by you or the Managing General Partner may be made in connection with meetings held by you or the Managing General Partner for the purpose of training or education of registered representatives of a Selling Agent, only if the following conditions are met: (i) the registered representative obtains his Selling Agent's prior approval to attend the meeting and attendance by the registered representative is not conditioned by his Selling Agent on the achievement of a sales target; (ii) the location of the training and education meeting is appropriate to the purpose of the meeting as defined in NASD Conduct Rule 2810; Anthem Securities, Inc. 4 Dealer-Manager Agreement (iii) the payment or reimbursement is not applied to the expenses of guests of the registered representative; (iv) the payment or reimbursement by you or the Managing General Partner is not conditioned by you or the Managing General Partner on the achievement of a sales target; and (v) the recordkeeping requirements are met. Non-cash compensation means any form of compensation received in connection with the sale of the Units that is not cash compensation, including but not limited to merchandise, gifts and prizes, travel expenses, meals and lodging. (c) Notwithstanding the foregoing: (i) the Managing General Partner, its officers, directors, and affiliates, and investors who buy Units through the officers and directors of the Managing General Partner may subscribe to Units for a subscription price reduced by the 2.5% Dealer-Manager fee, the 7% Sales Commission, the .5% accountable Reimbursement for Permissible Non-Cash Compensation, and the .5% reimbursement of the Selling Agents' bona fide accountable due diligence expenses, which shall not be paid to you; and (ii) registered investment advisors and their clients and Selling Agents and their registered representatives and principals may subscribe to Units for a subscription price reduced by the 7% Sales Commission, which shall not be paid to you, although their subscription price shall not be reduced by the 2.5% Dealer-Manager fee, the .5% accountable Reimbursement for Permissible Non-Cash Compensation, and the up to .5% reimbursement of the Selling Agents' bona fide accountable due diligence expenses which shall be paid to you. No more than 5% of the total Units sold in the Partnerships shall be sold, in the aggregate, with the discounts described above. (d) Pending receipt and acceptance by the Managing General Partner of the minimum subscription proceeds of $2,000,000 in each Partnership, excluding: (i) any optional subscription of the Managing General Partner and its Affiliates; and (ii) the subscription discounts set forth in Section 4(c) of this Agreement; all proceeds received by you from the sale of Units in each Partnership shall be held in a separate interest bearing escrow account as provided in Section 15 of this Agreement. Unless at least the minimum subscription proceeds of $2,000,000 as described above are received on or before the Offering Termination Date of a Partnership as described in Section 1 of this Agreement, the offering of Units in that Partnership shall be terminated, in which event: (i) the 2.5% Dealer-Manager fee, the 7% Sales Commission, the .5% accountable Reimbursement for Permissible Non-Cash Compensation, and the up to .5% reimbursement of the Selling Agents' bona fide accountable due diligence expenses set forth in Section 4(a) of this Agreement shall not be payable to you; (ii) all funds advanced by subscribers shall be returned to them with interest earned; and Anthem Securities, Inc. 5 Dealer-Manager Agreement (iii) you shall deliver a termination letter in the form provided to you by the Managing General Partner to each of the subscribers and to each of the offerees previously solicited by you and the Selling Agents in connection with the offering of the Units. (e) Except as otherwise provided below, the fees, reimbursements, and Sales Commissions set forth in Section 4(a) of this Agreement shall be paid to you within five business days after the following: (i) at least the minimum subscription proceeds of $2,000,000 as described above have been received by the respective Partnership and accepted by the respective Partnership; and (ii) the subscription proceeds have been released from the escrow account to the Partnership. You shall reallow to the Selling Agents and the wholesalers their respective fees, reimbursements, and Sales Commissions as set forth in Section 4(b) of this Agreement. Thereafter, your fees and Sales Commissions shall be paid to you and shall be reallowed to the Selling Agents and wholesalers as described above approximately every two weeks until the Offering Termination Date for the respective Partnership. All your remaining fees and Sales Commissions and your reimbursements shall be paid to you by the Managing General Partner no later than fourteen business days after the Offering Termination Date for the respective Partnership. 5. COVENANTS OF THE MANAGING GENERAL PARTNER. The Managing General Partner covenants and agrees that: (a) The Managing General Partner shall deliver to you ample copies of the Prospectus and all amendments or supplements to the Prospectus. (b) If any event affecting a Partnership or the Managing General Partner occurs that in the opinion of the Managing General Partner should be set forth in a supplement or amendment to the Prospectus, then the Managing General Partner shall promptly at its expense prepare and furnish to you a sufficient number of copies of a supplement or amendment to the Prospectus so that it, as so supplemented or amended, will not contain an untrue statement of a material fact or omit to state any material fact necessary in order to make the statements in the Prospectus, in the light of the circumstances under which they are made, not misleading. 6. REPRESENTATIONS AND WARRANTIES OF THE DEALER-MANAGER. You, as the Dealer-Manager, represent and warrant to the Managing General Partner and the respective Partnership that: (a) You are a corporation duly organized, validly existing and in good standing under the laws of the state of your formation or of any jurisdiction to the laws of which you are subject, with all requisite power and authority to enter into this Agreement and to carry out your obligations under this Agreement. (b) This Agreement when accepted and approved shall be duly authorized, executed, and delivered by you and shall be a valid and binding agreement on your part in accordance with its terms. (c) The consummation of the transactions contemplated by this Agreement and the Prospectus shall not result in the following: Anthem Securities, Inc. 6 Dealer-Manager Agreement (i) any breach of any of the terms or conditions of, or a default under your Articles of Incorporation or Bylaws, or any other indenture, agreement, or instrument to which you are a party or by which you are bound; or (ii) any violation of any order applicable to you of any court or regulatory body or administrative agency having jurisdiction over you or your affiliates. (d) You are duly registered under the provisions of the Securities Exchange Act of 1934, which is referred to as the "Act of 1934," as a broker or dealer, and you are a member in good standing of the NASD. You are duly registered as a broker/dealer in the states where you are required to be registered in order to carry out your obligations as contemplated by this Agreement and the Prospectus. You agree to maintain all the foregoing registrations in good standing throughout the term of the offer and sale of the Units in each Partnership, and you agree to comply with all statutes and other requirements applicable to you as a broker/dealer under those registrations. (e) Pursuant to your appointment as Dealer-Manager, you shall use your best efforts to exercise the supervision and control that you deem necessary and appropriate to the activities of you and the Selling Agents to comply with all the provisions of the Act, insofar as the Act applies to your and their activities under this Agreement. Further, you and the Selling Agents shall not engage in any activity which would cause the offer and/or sale of the Units not to comply with the Act, the Act of 1934, the applicable rules and regulations of the Commission, the applicable state securities laws and regulations, this Agreement, and the NASD Conduct Rules including Rules 2420, 2730, 2740, 2750, and Rule 2810(b)(2) and (b)(3), which provide as follows: Sec. (b)(2) SUITABILITY (A) A member or person associated with a member shall not underwrite or participate in a public offering of a direct participation program unless standards of suitability have been established by the program for participants therein and such standards are fully disclosed in the prospectus and are consistent with the provisions of subparagraph (B) of this section. (B) In recommending to a participant the purchase, sale or exchange of an interest in a direct participation program, a member or person associated with a member shall: (i) have reasonable grounds to believe, on the basis of information obtained from the participant concerning his investment objectives, other investments, financial situation and needs, and any other information known by the member or associated person, that: (a) the participant is or will be in a financial position appropriate to enable him to realize to a significant extent the benefits described in the prospectus, including the tax benefits where they are a significant aspect of the program; (b) the participant has a fair market net worth sufficient to sustain the risks inherent in the program, including loss of investment and lack of liquidity; and Anthem Securities, Inc. 7 Dealer-Manager Agreement (c) the program is otherwise suitable for the participant; and (ii) maintain in the files of the member documents disclosing the basis upon which the determination of suitability was reached as to each participant. (C) Notwithstanding the provisions of subparagraphs (A) and (B) hereof, no member shall execute any transaction in a direct participation program in a discretionary account without prior written approval of the transaction by the customer. Sec. (b)(3) DISCLOSURE (A) Prior to participating in a public offering of a direct participation program, a member or person associated with a member shall have reasonable grounds to believe, based on information made available to him by the sponsor through a prospectus or other materials, that all material facts are adequately and accurately disclosed and provide a basis for evaluating the program. (B) In determining the adequacy of disclosed facts pursuant to subparagraph (A) hereof, a member or person associated with a member shall obtain information on material facts relating at a minimum to the following, if relevant in view of the nature of the program: (i) items of compensation; (ii) physical properties; (iii) tax aspects; (iv) financial stability and experience of the sponsor; (v) the program's conflicts and risk factors; and (vi) appraisals and other pertinent reports. (C) For purposes of subparagraphs (A) and (B) hereof, a member or person associated with a member may rely upon the results of an inquiry conducted by another member or members, provided that: (i) the member or person associated with a member has reasonable grounds to believe that such inquiry was conducted with due care; (ii) the results of the inquiry were provided to the member or person associated with a member with the consent of the member or members conducting or directing the inquiry; and (iii) no member that participated in the inquiry is a sponsor of the program or an affiliate of such sponsor. Anthem Securities, Inc. 8 Dealer-Manager Agreement (D) Prior to executing a purchase transaction in a direct participation program, a member or person associated with a member shall inform the prospective participant of all pertinent facts relating to the liquidity and marketability of the program during the term of investment. You and the Selling Agents shall maintain records on the information used to determine that the investment in the Units is suitable and appropriate for each subscriber, and shall maintain these records for at least six years after the Offering Termination Date for the respective Partnership. (f) You agree to advise the Managing General Partner in writing of each jurisdiction in which you and the Selling Agents propose to offer or sell the Units; and you shall not nor shall you permit any Selling Agent to offer or sell the Units in any jurisdiction until you have been advised in writing by the Managing General Partner, or the Managing General Partner's special counsel, that the offer or sale of the Units: (i) has been qualified in the jurisdiction; (ii) is exempt from the qualification requirements imposed by the jurisdiction; or (iii) the qualification is otherwise not required. (g) You and the Selling Agents have received copies of the Prospectus relating to the Units and you and the Selling Agents have relied only on the statements contained in the Prospectus and not on any other statements whatsoever, either written or oral, with respect to the details of the offering of Units. You agree and shall require the Selling Agents to agree to deliver a copy of the Prospectus to each subscriber to whom you sell the Units at or before the completion of any sale of Units to such subscriber (which sale shall be deemed, for the purposes of this Agreement to occur on the date on which that subscriber delivers subscription funds to the escrow agent), or earlier if required by the Blue Sky or securities laws of any state. Unless advised otherwise by the Managing General Partner, you and the Selling Agents may choose to provide each offeree with the following, which are collectively referred to as the "Sales Literature": (i) a flyer entitled "Atlas America Public #14-2004 Program"; (ii) an article entitled "Tax Rewards with Oil and Gas Partnerships"; (iii) a brochure of tax scenarios entitled "How an Investment in Atlas America Public #14-2004 Program Can Help Achieve an Investor's Tax Objectives"; (iv) a brochure entitled "Investing in Atlas America Public #14-2004 Program"; (v) a booklet entitled "Outline of Tax Consequences of Oil and Gas Drilling Programs"; (vi) a brochure entitled "The Appalachian Basin: A Prime Drilling Location Which Commands a Premium"; (vii) a brochure entitled "Investment Insights - Tax Time"; (viii) a brochure entitled "Frequently Asked Questions"; and Anthem Securities, Inc. 9 Dealer-Manager Agreement (ix) possibly other supplementary materials. Any such Sales Literature, if distributed, must have been preceded or must be accompanied by the Prospectus. (h) You and the Selling Agents agree that you and the Selling Agents shall not place any advertisement or other solicitation with respect to the Units (including without limitation any material for use in any newspaper, magazine, radio or television commercial, telephone recording, motion picture, or other public media) without: (i) the prior written approval of the Managing General Partner; and (ii) the prior written approval of the form and content thereof by the Commission, the NASD and the securities authorities of the states where such advertisement or solicitation is to be circulated. Any such advertisements or solicitations shall be at your expense. (i) If a supplement or amendment to the Prospectus is prepared and delivered to you by the Managing General Partner, you agree and shall require any Selling Agent to agree as follows: (i) to distribute each supplement or amendment to the Prospectus to every person who has previously received a copy of the Prospectus from you and/or the Selling Agent; and (ii) to include each supplement or amendment in all future deliveries of any Prospectus. (j) In connection with any offer or sale of the Units, you agree and shall require any Selling Agent to agree to the following: (i) to comply in all respects with statements set forth in the Prospectus, the Partnership Agreement, and any supplements or amendments to the Prospectus; (ii) not to make any statement inconsistent with the statements in the Prospectus, the Partnership Agreement, and any supplements or amendments to the Prospectus; (iii) not to make any untrue statement of a material fact or omit to state a material fact necessary in order to make statements made, in light of the circumstances under which they were made, not misleading in connection with the Partnerships, the Units or the offering; and (iv) not to provide any written information, statements, or sales materials other than the Prospectus, the Sales Literature, and any supplements or amendments to the Prospectus unless approved in writing by the Managing General Partner. (k) You agree to use your best efforts in the solicitation and sale of the Units and to coordinate and supervise the efforts of the Selling Agents, and you shall require any Selling Agent to agree to use its best efforts in the solicitation and sale of the Units, including that: (i) the prospective purchasers meet the suitability requirements set forth in the Prospectus, the Subscription Agreement, and this Agreement; and Anthem Securities, Inc. 10 Dealer-Manager Agreement (ii) the prospective purchasers properly complete and execute the Subscription Agreement, which has been provided as Exhibit (I-B) to the Partnership Agreement, Exhibit (A) of the Prospectus, together with any additional forms provided in any supplement or amendment to the Prospectus, or otherwise provided to you by the Managing General Partner to be completed by prospective purchasers. The Managing General Partner shall have the right to reject any subscription at any time for any reason without liability to it. Subscription funds and executed Subscription Agreements shall be transmitted as set forth in Section 16 of this Agreement. (l) Although not anticipated, if you assist in any transfers of the Units, then you shall comply, and you shall require any Selling Agent to comply, with the requirements of Rule 2810(b)(2)(B) and (b)(3)(D) of the NASD Conduct Rules. (m) You agree and covenant that: (i) the representations and warranties you make in this Agreement are and shall be true and correct at the applicable closing date; and (ii) you shall have fulfilled all your obligations under this Agreement at the applicable closing date. 7. STATE SECURITIES REGISTRATION. Incident to the offer and sale of the Units, the Managing General Partner shall use its best efforts either in taking: (a) all necessary action and filing all necessary forms and documents deemed reasonable by it in order to qualify or register Units for sale under the securities laws of the jurisdictions requested by you pursuant to Section 6(f) of this Agreement; or (b) any necessary action and filing any necessary forms deemed reasonable by it in order to obtain an exemption from qualification or registration in those jurisdictions. Notwithstanding, the Managing General Partner may elect not to qualify or register Units in any state or jurisdiction in which it deems the qualification or registration is not warranted for any reason in its sole discretion. The Managing General Partner and its counsel shall inform you as to the states and jurisdictions in which the Units have been qualified for sale or are exempt under the respective securities or Blue Sky laws of those states and jurisdictions. The Managing General Partner, however, has not assumed and will not assume any obligation or responsibility as to your right or any Selling Agent's right to act as a broker/dealer with respect to the Units in any state or jurisdiction. The Managing General Partner shall provide to you and the Selling Agents for delivery to all offerees and purchasers and their representatives any additional information, documents, and instruments that the Managing General Partner deems necessary to comply with the rules, regulations, and judicial and administrative interpretations in those states and jurisdictions for the offer and sale of the Units in these states. The Managing General Partner shall file all post-offering forms, documents, or materials and take all other actions required by the states and jurisdictions in which the offer and sale of Units have been qualified, registered, or are exempt. However, the Managing General Partner shall not be required to take any action, make any filing, or prepare any document necessary or required in connection with your status or any Selling Agent's status as a broker/dealer under the laws of any state or jurisdiction. The Managing General Partner shall provide you with copies of all applications, filings, correspondence, orders, other documents, or instruments relating to any application for qualification, registration, exemption, or other approval under applicable state or Federal securities laws for the offering. Anthem Securities, Inc. 11 Dealer-Manager Agreement 8. EXPENSE OF SALE. The expenses in connection with the offer and sale of the Units shall be payable as set forth below. (a) The Managing General Partner shall pay all expenses incident to the performance of its obligations under this Agreement, including the fees and expenses of its attorneys and accountants and all fees and expenses of registering or qualifying the Units for offer and sale in the states and jurisdictions as set forth in Section 7 of this Agreement, or obtaining exemptions from qualification or registration, even if the offering of the Partnerships is not successfully completed. (b) You shall pay all expenses incident to the performance of your obligations under this Agreement, including the formation and management of the selling group and the fees and expenses of your own counsel and accountants, even if the offering of the Partnerships is not successfully completed. 9. CONDITIONS OF THE DEALER-MANAGER'S DUTIES. Your obligations under this Agreement shall be subject to the accuracy, as of the date of this Agreement and at the applicable closing date of: (a) the Managing General Partner's representations and warranties made in this Agreement; and (b) to the performance by the Managing General Partner of its obligations under this Agreement. 10. CONDITIONS OF THE MANAGING GENERAL PARTNER'S DUTIES. The Managing General Partner's obligations provided under this Agreement, including the duty to pay compensation to you as set forth in Section 4 of this Agreement, shall be subject to the following: (a) the accuracy, as of the date of this Agreement and at the applicable closing date of each Partnership as if made at the applicable closing date, of your representations and warranties made in this Agreement; (b) the performance by you of your obligations under this Agreement; and (c) the Managing General Partner's receipt, at or before the applicable closing date of each Partnership, of a fully executed Subscription Agreement for each prospective purchaser as required by Section 6(k) of this Agreement. 11. INDEMNIFICATION. (a) You and the Selling Agents shall indemnify and hold harmless the Managing General Partner, each Partnership and its attorneys against any losses, claims, damages or liabilities, joint or several, to which they may become subject under the Act, the Act of 1934, or otherwise insofar as the losses, claims, damages, or liabilities (or actions in respect thereof) arise out of or are based on your agreements with the Selling Agents or your breach of any of your duties and obligations, representations, or warranties under the terms or provisions of this Agreement, and you and the Selling Agents shall reimburse them for any legal or other expenses reasonably incurred in connection with investigating or defending the losses, claims, damages, liabilities, or actions. Anthem Securities, Inc. 12 Dealer-Manager Agreement (b) The Managing General Partner shall indemnify and hold you and the Selling Agents harmless against any losses, claims, damages or liabilities, joint or several, to which you and the Selling Agents may become subject under the Act, the Act of 1934, or otherwise insofar as the losses, claims, damages, or liabilities (or actions in respect thereof) arise out of or are based on the Managing General Partner's breach of any of its duties and obligations, representations, or warranties under the terms or provisions of this Agreement, and the Managing General Partner shall reimburse you and the Selling Agents for any legal or other expenses reasonably incurred in connection with investigating or defending the losses, claims, damages, liabilities, or actions. (c) The foregoing indemnity agreements shall extend on the same terms and conditions to, and shall inure to the benefit of, each person, if any, who controls each indemnified party within the meaning of the Act. (d) Promptly after receipt by an indemnified party of notice of the commencement of any action, the indemnified party shall, if a claim in respect of the action is to be made against an indemnifying party under this Section, notify the indemnifying party in writing of the commencement of the action; but the omission to promptly notify the indemnifying party shall not relieve the indemnifying party from any liability which it may have to any indemnified party. If any action is brought against an indemnified party, it shall notify the indemnifying party of the commencement of the action, and the indemnifying party shall be entitled to participate in, and, to the extent that it wishes, jointly with any other indemnifying party similarly notified, to assume the defense of the action, with counsel satisfactory to the indemnified and indemnifying parties. After the indemnified party has received notice from the agreed on counsel that the defense of the action under this paragraph has been assumed, the indemnifying party shall not be responsible for any legal or other expenses subsequently incurred by the indemnified party in connection with the defense of the action other than with respect to the agreed on counsel who assumed the defense of the action. 12. REPRESENTATIONS AND AGREEMENTS TO SURVIVE DELIVERY. All representations, warranties, and agreements of the Managing General Partner and you in this Agreement, including the indemnity agreements contained in Section 11 of this Agreement, shall: (a) survive the delivery, execution and closing of this Agreement; and (b) remain operative and in full force and effect regardless of any investigation made by or on behalf of you or any person who controls you within the meaning of the Act, by the Managing General Partner, or any of its officers, directors, or any person who controls the Managing General Partner within the meaning of the Act, or any other indemnified party; and (c) survive delivery of the Units. 13. TERMINATION. (a) You shall have the right to terminate this Agreement other than the indemnification provisions of Section 11 of this Agreement by giving notice as specified below any time at or before a closing date: (i) if the Managing General Partner has failed, refused, or been unable at or before a closing date, to perform any of its obligations under this Agreement; or (ii) there has occurred an event materially and adversely affecting the value of the Units. Anthem Securities, Inc. 13 Dealer-Manager Agreement (b) The Managing General Partner may terminate this Agreement other than the indemnification provisions of Section 11 of this Agreement, for any reason and at any time, by promptly giving notice to you by telephone, e-mail, facsimile, or telegram, confirmed by letter as specified below at or before a closing date. 14. NOTICES. (a) All notices or communications under this Agreement, except as otherwise specifically provided, shall be in writing. (b) Any notice or communication sent by the Managing General Partner or a Partnership to you shall be mailed, delivered, or sent by facsimile, e-mail or telegraph, and confirmed to you at P.O. Box 926, 311 Rouser Road, Moon Township, Pennsylvania 15108-0926. (c) Any notice or communication sent by you to the Managing General Partner or a Partnership shall be mailed, delivered, or sent by facsimile, e-mail or telegraph, and confirmed at 311 Rouser Road, Moon Township, Pennsylvania 15108. 15. FORMAT OF CHECKS/ESCROW AGENT. Pending receipt of the minimum subscription proceeds of $2,000,000 of each Partnership as set forth in Section 4(d) of this Agreement, the Managing General Partner and you and the Selling Agents, including customer carrying broker/dealers, agree that all subscribers shall be instructed to make their checks or wires payable solely to the Escrow Agent for the Partnership in which the Units are then being offered as follows: (a) "Atlas Public #14-2004 L.P., Escrow Agent, National City Bank of PA"; (b) "Atlas Public #14-2005(A) L.P., Escrow Agent, National City Bank of PA"; or (c) "Atlas Public #14-2005(B) L.P., Escrow Agent, National City Bank of PA"; as agent for the respective Partnership then being offered. You agree and shall require the Selling Agents, including customer carrying broker/dealers, to agree to comply with Rule 15c2-4 adopted under the Act of 1934. In addition, for identification purposes, wire transfers should reference the subscriber's name and the account number of the escrow account for the Partnership in which the Units are then being offered. If you receive a check not conforming to the foregoing instructions, then you shall return the check to the Selling Agent not later than the end of the next business day following its receipt by you. The Selling Agent shall then return the check directly to the subscriber not later than the end of the next business day following its receipt from you. Checks received by you or a Selling Agent which conform to the foregoing instructions shall be transmitted by you under Section 16 "Transmittal Procedures," below. You represent that you have or will execute the Escrow Agreement for each Partnership and agree that you are bound by the terms of the Escrow Agreement executed by you, for the respective Partnership, and the Managing General Partner, the form of which is attached to this Agreement as Exhibit "A." 16. TRANSMITTAL PROCEDURES. You and each Selling Agent, including customer carrying broker/dealers, shall transmit received investor funds in accordance with the following procedures. For purposes of the following, the term "Selling Agent" shall also include you as Dealer-Manager when you receive subscriptions from investors. Anthem Securities, Inc. 14 Dealer-Manager Agreement (a) Pending receipt of a Partnership's minimum subscription proceeds of $2,000,000 as set forth in Section 4(d) of this Agreement, the Selling Agents on receipt of any check from a subscriber shall promptly transmit the check and the original executed Subscription Agreement to you, as Dealer-Manager, by the end of the next business day following receipt of the check by the Selling Agent. By the end of the next business day following your receipt of the check and the original executed Subscription Agreement, you, as Dealer-Manager, shall transmit the check and a copy of the executed Subscription Agreement to the Escrow Agent, and the original executed Subscription Agreement and a copy of the check to the Managing General Partner. (b) On receipt by you, as Dealer-Manager, of notice from the Managing General Partner that a Partnership's minimum subscription proceeds of $2,000,000 as set forth in Section 4(d) of this Agreement have been received, the Managing General Partner, you, and the Selling Agents agree that all subscribers then may be instructed, in the Managing General Partner's sole discretion, to make their checks or wires payable solely to the Partnership in which Units are then being offered. Thereafter, the Selling Agents shall promptly transmit any and all checks received from subscribers and the original executed Subscription Agreement to you, as Dealer-Manager, by the end of the next business day following receipt of the check by the Selling Agent. By the end of the next business day following your receipt of the check and the original executed Subscription Agreement, you, as Dealer-Manager, shall transmit the check and the original executed Subscription Agreement to the Managing General Partner. 17. PARTIES. This Agreement shall inure to the benefit of and be binding on you, the Managing General Partner, and any respective successors and assigns. This Agreement shall also inure to the benefit of the indemnified parties, their successors and assigns. This Agreement is intended to be and is for the sole and exclusive benefit of the parties to this Agreement, including the Partnerships, and their respective successors and assigns, and the indemnified parties and their successors and assigns, and for the benefit of no other person. No other person shall have any legal or equitable right, remedy or claim under or in respect of this Agreement. No purchaser of any of the Units from you or a Selling Agent shall be construed a successor or assign merely by reason of the purchase. 18. RELATIONSHIP. This Agreement shall not constitute you a partner of the Managing General Partner, a Partnership, or any general partner of a Partnership, nor render the Managing General Partner, the Partnerships, or any general partner of a Partnership liable for any of your obligations. 19. EFFECTIVE DATE. This Agreement is made effective between the parties as of the date accepted by you as indicated by your signature to this Agreement. 20. ENTIRE AGREEMENT, WAIVER. (a) This Agreement constitutes the entire agreement between the Managing General Partner and you, and shall not be amended or modified in any way except by subsequent agreement executed in writing. Neither party to this Agreement shall be liable or bound to the other by any agreement except as specifically set forth in this Agreement. (b) The Managing General Partner and you may waive, but only in writing, any term, condition, or requirement under this Agreement that is intended for its benefit. However, any written waiver of any term or condition of this Agreement shall not operate as a waiver of any other breach of that term or condition of this Agreement. Also, any failure to enforce any provision of this Agreement shall not operate as a waiver of that provision or any other provision of this Agreement. Anthem Securities, Inc. 15 Dealer-Manager Agreement 21. GOVERNING LAW. This Agreement shall be governed and construed in accordance with the laws of the Commonwealth of Pennsylvania. 22. COMPLAINTS. The Managing General Partner and you, as Dealer-Manager, agree as follows: (a) to notify the other if either receives an investor complaint in connection with the offer or sale of Units by you or a Selling Agent; (b) to cooperate with the other in resolving the complaint; and (c) to cooperate in any regulatory examination of the other to the extent it involves this Agreement or the offer or sale of Units by you or a Selling Agent. 23. PRIVACY. The Managing General Partner and you each acknowledge that certain information made available to the other under this Agreement may be deemed nonpublic personal information under the Gramm-Leach-Bliley Act, other federal or state privacy laws (as amended), and the rules and regulations promulgated thereunder, which are referred to collectively, as the "Privacy Laws." The Managing General Partner and you agree as follows: (a) not to disclose or use the information except as required to carry out each party's respective duties under this Agreement or as otherwise permitted by law in the ordinary course of business; (b) to establish and maintain procedures reasonably designated to assure the security and privacy of all the information; and (c) to cooperate with the other and provide reasonable assistance in ensuring compliance with the Privacy Laws to the extent applicable to either or both the Managing General Partner and you. 24. ANTI-MONEY LAUNDERING PROVISION. You and each Selling Agent each represent and warrant to the Managing General Partner that each of you have in place and will maintain suitable and adequate "know your customer" policies and procedures and that each of you shall comply with all applicable laws and regulations regarding anti-money laundering activity and will provide such documentation to the Managing General Partner on written request. 25. ACCEPTANCE. Please confirm your agreement to the terms and conditions set forth above by signing and returning the enclosed duplicate copy of this Agreement to us at the address set forth above. Very truly yours, MANAGING GENERAL PARTNER ATLAS RESOURCES, INC., a Pennsylvania corporation , 2004 By: - ----------------------- --------------------------------- Date Jack L. Hollander, Senior Vice President - Direct Participation Programs Anthem Securities, Inc. 16 Dealer-Manager Agreement PROGRAM ATLAS AMERICA PUBLIC #14-2004 PROGRAM By: Atlas Resources, Inc., Managing General Partner , 2004 By: - ----------------------- ------------------------------- Date Jack L. Hollander, Senior Vice President - Direct Participation Programs DEALER-MANAGER ANTHEM SECURITIES, INC., a Pennsylvania corporation , 2004 By: - ----------------------- ------------------------------- Date Justin Atkinson, President Anthem Securities, Inc. 17 Dealer-Manager Agreement EXHIBIT "A" ATLAS AMERICA PUBLIC #14-____________ L.P. ESCROW AGREEMENT THIS AGREEMENT is made to be effective as of ________________, by and among Atlas Resources, Inc., a Pennsylvania corporation (the "Managing General Partner"), Anthem Securities, Inc., a Pennsylvania corporation ("Anthem"), Bryan Funding, Inc., a Pennsylvania corporation ("Bryan Funding"), collectively Anthem and Bryan Funding are referred to as the "Dealer-Manager," Atlas America Public #14-_________ L.P., a Delaware limited partnership (the "Partnership") and National City Bank of Pennsylvania, Pittsburgh, Pennsylvania, as escrow agent (the "Escrow Agent"). WITNESSETH: WHEREAS, the Managing General Partner intends to offer publicly for sale to qualified investors (the "Investors") up to 12,500 limited and investor general partner interests in the Partnership (the "Units"). WHEREAS, each Investor will be required to pay his subscription in full on subscribing by check or wire (the "Subscription Proceeds"). WHEREAS, the cost per Unit will be $10,000 subject to certain discounts of up to10.5% ($1,050 per Unit) for sales to the Managing General Partner, its officers, directors and affiliates, registered investment advisors and their clients, Selling Agents and their registered representatives and principals, and investors who buy Units through the officers and directors of the Managing General Partner. Also, the Managing General Partner, in its discretion, may accept one-half Unit ($5,000) subscriptions, with larger subscriptions permitted in $1,000 increments. WHEREAS, the Managing General Partner and Anthem have executed an agreement ("Anthem Dealer-Manager Agreement") under which Anthem will solicit subscriptions for Units in all states other than Minnesota and New Hampshire on a "best efforts" "all or none" basis for Subscription Proceeds of $2,000,000 and on a "best efforts" basis for the remaining Units on behalf of the Managing General Partner and the Partnership and under which Anthem has been authorized to select certain members in good standing of the National Association of Securities Dealers, Inc. ("NASD") to participate in the offering of the Units ("Selling Agents"). WHEREAS, the Managing General Partner and Bryan Funding have executed an agreement ("Bryan Funding Dealer-Manager Agreement") under which Bryan Funding will solicit subscriptions for Units in the states of Minnesota and New Hampshire on a "best efforts" "all or none" basis for Subscription Proceeds of $2,000,000 and on a "best efforts" basis for the remaining Units on behalf of the Managing General Partner and the Partnership and under which Bryan Funding has been authorized to select certain members in good standing of the NASD to participate in the offering of the Units ("Selling Agents"). WHEREAS, the Anthem Dealer-Manager Agreement and the Bryan Funding Dealer-Manager Agreement, collectively referred to as the "Dealer-Manager Agreement," provide for compensation to the Dealer-Manager to participate in the offering of the Units, subject to the discounts set forth above for certain Investors, which compensation includes, but is not limited to, for each Unit sold: o a 2.5% Dealer-Manager fee; o a 7% sales commission; Escrow Agreement 1 o a .5% accountable Reimbursement for Permissible Non-Cash Compensation; and o an up to .5% reimbursement of the Selling Agents' bona fide accountable due diligence expenses; all or a portion of which will be reallowed to the Selling Agents and wholesalers. WHEREAS, under the terms of the Dealer-Manager Agreement the Subscription Proceeds are required to be held in escrow subject to the receipt and acceptance by the Managing General Partner of the minimum Subscription Proceeds of $2,000,000, excluding any optional subscription by the Managing General Partner, its officers, directors, and Affiliates. WHEREAS, the Units may also be offered and sold by the officers and directors of the Managing General Partner without receiving a sales commission or other compensation on their sales. WHEREAS, no subscriptions to the Partnership will be accepted after the "Offering Termination Date," which is the first to occur of either: o receipt of the maximum Subscription Proceeds of $125,000,000; or o _____________________. WHEREAS, to facilitate compliance with the terms of the Dealer-Manager Agreement and Rule 15c2-4 adopted under the Securities Exchange Act of 1934, the Managing General Partner and the Dealer-Manager desire to have the Subscription Proceeds deposited with the Escrow Agent and the Escrow Agent agrees to hold the Subscription Proceeds under the terms and conditions set forth in this Agreement. NOW, THEREFORE, in consideration of the mutual covenants and conditions contained in this Agreement, the parties to this Agreement, intending to be legally bound, agree as follows: 1. APPOINTMENT OF ESCROW AGENT. The Managing General Partner, the Partnership, and the Dealer-Manager appoint the Escrow Agent as the escrow agent to receive and to hold the Subscription Proceeds deposited with the Escrow Agent by the Dealer-Manager and the Managing General Partner under this Agreement, and the Escrow Agent agrees to serve in this capacity during the term and based on the provisions of this Agreement. 2. DEPOSIT OF SUBSCRIPTION PROCEEDS. Pending receipt of the minimum Subscription Proceeds of $2,000,000, the Dealer-Manager and the Managing General Partner shall deposit the Subscription Proceeds of each Investor to whom they sell Units with the Escrow Agent and shall deliver to the Escrow Agent a copy of the "Subscription Agreement," which is the execution and subscription instrument signed by the Investor to evidence his agreement to purchase Units in the Partnership. Payment for each subscription for Units shall be in the form of a check or wire made payable to "Atlas America Public #14-______ L.P., Escrow Agent, National City Bank of Pennsylvania." 3. INVESTMENT OF SUBSCRIPTION PROCEEDS. The Subscription Proceeds shall be deposited in an interest bearing account maintained by the Escrow Agent as directed by the Managing General Partner. This may be a savings account, bank money market account, short-term certificates of deposit issued by a bank, or short-term certificates issued or guaranteed by the United States government. The interest earned shall be added to the Subscription Proceeds and disbursed in accordance with the provisions of Paragraph 4 or 5 of this Agreement, as the case may be. Escrow Agreement 2 4. DISTRIBUTION OF SUBSCRIPTION PROCEEDS. If the Escrow Agent: (a) receives proper written notice from an authorized officer of the Managing General Partner that at least the minimum Subscription Proceeds of $2,000,000 have been received and accepted by the Managing General Partner; and (b) determines that Subscription Proceeds for at least $2,000,000 are Distributable Subscription Proceeds; then the Escrow Agent shall promptly release and distribute to the Managing General Partner the Distributable Subscription Proceeds plus any interest paid and investment income earned on the Subscription Proceeds while held by the Escrow Agent in the escrow account. For purposes of the Agreement, "Distributable Subscription Proceeds" are Subscription Proceeds which have been deposited in the escrow account (1) by check, but only to the extent the Escrow Agent believes an amount of time has passed which would usually be sufficient for Subscription Proceeds paid by check to have returned unpaid by the bank on which the check was drawn and become Distributable Subscription Proceeds after a 10 day period from the date of deposit and (2) by wire transfer. After the occurrence of 4(a) and (b) above, Escrow Agent will provide a letter to the Managing General Partner confirming receipt of checks and/or wires representing Subscription Proceeds totaling at least $2,000,000 have been received and the anticipated date the funds will be considered Distributable Subscription Proceeds. After the initial distribution, any remaining Subscription Proceeds, plus any interest paid and investment income earned on the Subscription Proceeds while held by the Escrow Agent in the escrow account, shall be promptly released and distributed to the Managing General Partner by the Escrow Agent as the Subscription Proceeds become Distributable Subscription Proceeds after a 10 day period from the date of deposit. The Managing General Partner shall immediately return to the Escrow Agent any Subscription Proceeds distributed to the Managing General Partner or refunded to an Investor to the extent that such Subscription Proceeds were paid by a check which is returned or otherwise not collected for any reason prior or subsequent to termination of this Agreement. 5. SEPARATE PARTNERSHIP ACCOUNT. During the continuation of the offering after the Partnership is funded with cleared Subscription Proceeds of at least $2,000,000 and the Escrow Agent provides notice described in Paragraph 4 of this Agreement, and before the Offering Termination Date, any additional Subscription Proceeds may be deposited by the Dealer-Manager and the Managing General Partner directly in a separate Partnership account which shall not be subject to the terms of this Agreement. 6. DISTRIBUTIONS TO SUBSCRIBERS. (a) If the Partnership is not funded as contemplated because less than the minimum Subscription Proceeds of $2,000,000 have been received and accepted by the Managing General Partner by twelve (12:00) p.m. (noon), local time, EASTERN STANDARD TIME on the Offering Termination Date, or for any other reason, then the Managing General Partner shall notify the Escrow Agent, and the Escrow Agent promptly shall distribute to each Investor, for which Escrow Agent has a copy of a Subscription Agreement, a refund check made payable to the Investor in an amount equal to the Subscription Proceeds of the Investor, plus any interest paid or investment income earned on the Investor's Subscription Proceeds while held by the Escrow Agent in the escrow account. Escrow Agreement 3 (b) If a subscription for Units submitted by an Investor is rejected by the Managing General Partner for any reason after the Subscription Proceeds relating to the subscription have been deposited with the Escrow Agent, then the Managing General Partner promptly shall notify in writing, the Escrow Agent of the rejection, and the Escrow Agent shall promptly distribute to the Investor a refund check made payable to the Investor, for which Escrow Agent has a copy of a Subscription Agreement, in an amount equal to the Subscription Proceeds of the Investor, plus any interest paid or investment income earned on the Investor's Subscription Proceeds while held by the Escrow Agent in the escrow account. 7. COMPENSATION AND EXPENSES OF ESCROW AGENT. The Managing General Partner shall be solely responsible for and shall pay the compensation of the Escrow Agent for its services under this Agreement, as provided in Appendix 1 to this Agreement and made a part of this Agreement, and the charges, expenses (including any reasonable attorneys' fees), and other out-of-pocket expenses incurred by the Escrow Agent in connection with the administration of the provisions of this Agreement. The Escrow Agent shall have no lien on the Subscription Proceeds deposited in the escrow account unless and until the Partnership is funded with cleared Subscription Proceeds of at least $2,000,000 and the Escrow Agent receives the proper written notice described in Paragraph 4 of this Agreement, at which time the Escrow Agent shall have, and is granted, a prior lien on any property, cash, or assets held under this Agreement, with respect to its unpaid compensation and nonreimbursed expenses, superior to the interests of any other persons or entities. 8. DUTIES OF ESCROW AGENT. The Escrow Agent shall not be obligated to accept any notice, make any delivery, or take any other action under this Agreement unless the notice or request or demand for delivery or other action is in writing and given or made by the Managing General Partner or an authorized officer of the Managing General Partner. In no event shall the Escrow Agent be obligated to accept any notice, request, or demand from anyone other than the Managing General Partner. 9. LIABILITY OF ESCROW AGENT. The Escrow Agent shall not be liable for any damages, or have any obligations other than the duties prescribed in this Agreement in carrying out or executing the purposes and intent of this Agreement. However, nothing in this Agreement shall relieve the Escrow Agent from liability arising out of its own willful misconduct or gross negligence. The Escrow Agent's duties and obligations under this Agreement shall be entirely administrative and not discretionary. The Escrow Agent shall not be liable to any party to this Agreement or to any third-party as a result of any action or omission taken or made by the Escrow Agent in good faith. The parties to this Agreement will jointly and severally indemnify the Escrow Agent, hold the Escrow Agent harmless, and reimburse the Escrow Agent from, against and for, any and all liabilities, costs, fees and expenses (including reasonable attorney's fees) the Escrow Agent may suffer or incur by reason of its execution and performance of this Agreement. If any legal questions arise concerning the Escrow Agent's duties and obligations under this Agreement, then the Escrow Agent may consult with its counsel and rely without liability on written opinions given to it by its counsel. The Escrow Agent shall be protected in acting on any written notice, request, waiver, consent, authorization, or other paper or document which the Escrow Agent, in good faith, believes to be genuine and what it purports to be. If there is any disagreement between any of the parties to this Agreement, or between them or any other person, resulting in adverse claims or demands being made in connection with this Agreement, or if the Escrow Agent, in good faith, is in doubt as to what action it should take under this Agreement, then the Escrow Agent may, at its option, refuse to comply with any claims or demands on it or refuse to take any other action under this Agreement, so long as the disagreement continues or the doubt exists. In any such event, the Escrow Agent shall not be or become liable in any way or to any person for its failure or refusal to act and the Escrow Agent shall be entitled to continue to so refrain from acting until the dispute is resolved by the parties involved. Escrow Agreement 4 National City Bank of Pennsylvania is acting solely as the Escrow Agent and is not a party to, nor has it reviewed or approved any agreement or matter of background related to this Agreement, other than this Agreement itself, and has assumed, without investigation, the authority of the individuals executing this Agreement to be so authorized on behalf of the party or parties involved. 10. RESIGNATION OR REMOVAL OF ESCROW AGENT. The Escrow Agent may resign as such after giving thirty days' prior written notice to the other parties to this Agreement. Similarly, the Escrow Agent may be removed and replaced after receiving thirty days' prior written notice from the other parties to this Agreement. In either event, the duties of the Escrow Agent shall terminate thirty days after the date of the notice (or as of an earlier date as may be mutually agreeable); and the Escrow Agent shall then deliver the balance of the Subscription Proceeds (and any interest paid or investment income earned thereon while held by the Escrow Agent in the escrow account) in its possession to a successor escrow agent appointed by the other parties to this Agreement as evidenced by a written notice filed with the Escrow Agent. If the other parties to this Agreement are unable to agree on a successor escrow agent or fail to appoint a successor escrow agent before the expiration of thirty days following the date of the notice of the Escrow Agent's resignation or removal, then the Escrow Agent may petition any court of competent jurisdiction for the appointment of a successor escrow agent or other appropriate relief. Any resulting appointment shall be binding on all of the parties to this Agreement. On acknowledgment by any successor escrow agent of the receipt of the then remaining balance of the Subscription Proceeds (and any interest paid or investment income earned thereon while held by the Escrow Agent in the escrow account), the Escrow Agent shall be fully released and relieved of all duties, responsibilities, and obligations under this Agreement. 11. TERMINATION. This Agreement shall terminate and the Escrow Agent shall have no further obligation with respect to this Agreement after the distribution of all Subscription Proceeds (and any interest paid or investment income earned thereon while held by the Escrow Agent in the escrow account) as contemplated by this Agreement or on the written consent of all the parties to this Agreement. 12. NOTICE. Any notices or instructions, or both, to be given under this Agreement shall be validly given if set forth in writing and mailed by certified mail, return receipt requested, or by facsimile with confirmation of receipt (originals to be followed in the mail), or by a nationally recognized overnight courier, as follows: If to the Escrow Agent: National City Bank 1900 East 9th Street Cleveland, Ohio 44114 Attention: Dawn DeWerth LOC 2111 Phone: (216) 222-9225 Facsimile: (216) 222-7044 Escrow Agreement 5 If to the Managing General Partner: Atlas Resources, Inc. 311 Rouser Road P.O. Box 611 Moon Township, Pennsylvania 15108 Attention: Karen A. Black Phone: (412) 262-2830 Facsimile: (412) 262-2820 If to Anthem: Anthem Securities, Inc. 311 Rouser Road P.O. Box 926 Moon Township, Pennsylvania 15108 Attention: Justin T. Atkinson Phone: (412) 262-1680 Facsimile: (412) 262-7430 If to Bryan Funding: Bryan Funding, Inc. 393 Vanadium Road Pittsburgh, Pennsylvania 15243 Attention: Richard G. Bryan, Jr. Phone: (412) 276-9393 Facsimile: (412) 276-9396 Any party may designate any other address to which notices and instructions shall be sent by notice duly given in accordance with this Agreement. 13. MISCELLANEOUS. (a) This Agreement shall be governed by and construed in accordance with the laws of the Commonwealth of Pennsylvania. (b) This Agreement shall be binding on and shall inure to the benefit of the undersigned and their respective successors and assigns. (c) This Agreement may be executed in multiple copies, each executed copy to serve as an original. Escrow Agreement 6 14. The parties hereto and subscribers acknowledge Escrow Agent has not reviewed and is not making any recommendations with respect to the securities offered. IN WITNESS WHEREOF, the parties hereto have executed this Agreement to be effective as of the day and year first above written. NATIONAL CITY BANK OF PENNSYLVANIA As Escrow Agent By: -------------------------------------------- (Authorized Officer) ATLAS RESOURCES, INC. A Pennsylvania corporation By: -------------------------------------------- Karen A. Black, Vice President - Partnership Administration ANTHEM SECURITIES, INC. A Pennsylvania corporation By: -------------------------------------------- Justin T. Atkinson, President BRYAN FUNDING, INC. A Pennsylvania corporation By: -------------------------------------------- Richard G. Bryan, Jr., President ATLAS AMERICA PUBLIC #14-______ L.P. By: ATLAS RESOURCES, INC. Managing General Partner By: -------------------------------------------- Karen A. Black, Vice President - Partnership Administration Escrow Agreement 7 APPENDIX I TO ESCROW AGREEMENT COMPENSATION FOR SERVICES OF ESCROW AGENT REVIEW AND ACCEPTANCE FEE: $ WAIVED For providing initial review of the Escrow Agreement and all supporting documents and for initial services associated with establishing the Escrow Account. This is a one (1) time fee payable upon the opening of the account. I. Annual Administrative Fee Payable in Advance $3000.00 (or any portion thereof) II. Remittance of checks returned to subscribers 20.00 (set out in section 6 of the governing agreement) III. Wire transfers n/a IV. Purchase or Sale of Securities 100.00 V. Investments (document limits investment to a checking or savings account, or certificates of deposit) such products offered by any National City Bank retail branch)- fees are subject to the type of account the Managing General Partner directs the Escrow Agent to open and to be governed by the Escrow Agreement. EXTRAORDINARY SERVICES: For any services other than those covered by the aforementioned, a special per hour charge will be made commensurate with the character of the service, time required and responsibility involved. Such services include but are not limited to excessive administrative time, attendance at closings, specialized reports, and record keeping, unusual certifications, etc. Managing General Partner agrees to report all funds in accordance with appropriate tax treatment. FEE SCHEDULE IS SUBJECT TO ANNUAL REVIEW AND/or ADJUSTMENT UPON AMENDMENT THERETO. Escrow Agreement 8 EXHIBIT "B" SELLING AGENT AGREEMENT WITH ANTHEM SECURITIES, INC. TO: _________________________________________________ RE: ATLAS AMERICA PUBLIC #14-2004 PROGRAM --------------------------------------- Gentlemen: Atlas Resources, Inc. will be the Managing General Partner in a series of up to three limited partnerships to be organized under the Delaware Revised Uniform Limited Partnership Act: o Atlas America Public #14-2004 L.P.; o Atlas America Public #14-2005(A) L.P.; and o Atlas America Public #14-2005(B) L.P. which are referred to as the "Partnership" or the "Partnerships." The Units in the Partnerships, which are referred to as the "Units," and the offering are described in the Prospectus, copies of which have been furnished to you with this Agreement. Our firm, Anthem Securities, Inc., which is referred to as the "Dealer-Manager," has entered into a Dealer-Manager Agreement for sales in all states other than Minnesota and New Hampshire, a copy of which has been furnished to you and is incorporated in this Agreement by reference, with the Managing General Partner and the Partnerships under which the Dealer-Manager has agreed to form a group of NASD member firms, which are referred to as the "Selling Agents." The Selling Agents will obtain subscriptions for Units in each Partnership in all states other than: o Minnesota; and o New Hampshire on a "best efforts" basis under the Securities Act of 1933, as amended, which is referred to as the "Act," and the provisions of the Prospectus. You are invited to become one of the Selling Agents on a non-exclusive basis. By your acceptance below you agree to act in that capacity and to use your best efforts, in accordance with the terms and conditions of this Agreement, to solicit subscriptions for Units in each Partnership at the time the Partnership is being offered as provided in Section 1 of the Dealer-Manager Agreement in all states other than: o Minnesota; and o New Hampshire. Anthem Securities, Inc. 1 Selling Agent Agreement This Agreement, however, shall not be construed to prohibit your participation as a selling agent in Minnesota and New Hampshire under a duly executed selling agent agreement entered into by you and any other authorized "Dealer-Manager" for the Partnerships. 1. REPRESENTATIONS AND WARRANTIES OF SELLING AGENT. You represent and warrant to the Dealer-Manager that: (a) You are a corporation or other entity duly organized, validly existing, and in good standing under the laws of the state of your formation or of any jurisdiction to the laws of which you are subject, with all requisite power and authority to enter into this Agreement and to carry out your obligations under this Agreement. (b) This Agreement when accepted and approved by you will be duly authorized, executed, and delivered by you and will be a valid and binding agreement on your part in accordance with its terms. (c) The consummation of the transactions contemplated by this Agreement and the Prospectus will not result in the following: (i) any breach of any of the terms or conditions of, or constitute a default under your organizational documents, bylaws, any indenture, agreement, or other instrument to which you are a party or by which you are bound; or (ii) any violation of any order applicable to you of any court, regulatory body or administrative agency having jurisdiction over you or over your affiliates. (d) You are duly registered under the provisions of the Securities Exchange Act of 1934, which is referred to as the "Act of 1934," as a broker/dealer, and you are a member in good standing of the NASD. You are duly registered as a broker/dealer in the jurisdictions where you are required to be registered in order to carry out your obligations as contemplated by this Agreement and the Prospectus. You agree to maintain all the foregoing registrations in good standing throughout the term of the offer and sale of the Units, and you agree to comply with all statutes and other requirements applicable to you as a broker/dealer under those registrations. (e) Pursuant to your appointment as a Selling Agent, you shall comply with all the provisions of the Act, insofar as the Act applies to your activities under this Agreement. Further, you shall not engage in any activity which would cause the offer and/or sale of the Units not to comply with the Act, the Act of 1934, the applicable rules and regulations of the Securities and Exchange Commission, which is referred to as the "Commission," the applicable state securities laws and regulations, this Agreement, and the NASD Conduct Rules including Rules 2420, 2730, 2740, 2750, and 2810(b)(2) and (b)(3), which provide as follows: Sec. (b)(2) SUITABILITY (A) A member or person associated with a member shall not underwrite or participate in a public offering of a direct participation program unless standards of suitability have been established by the program for participants therein and such standards are fully disclosed in the prospectus and are consistent with the provisions of subparagraph (B) of this section. Anthem Securities, Inc. 2 Selling Agent Agreement (B) In recommending to a participant the purchase, sale or exchange of an interest in a direct participation program, a member or person associated with a member shall: (i) have reasonable grounds to believe, on the basis of information obtained from the participant concerning his investment objectives, other investments, financial situation and needs, and any other information known by the member or associated person, that: (a) the participant is or will be in a financial position appropriate to enable him to realize to a significant extent the benefits described in the prospectus, including the tax benefits where they are a significant aspect of the program; (b) the participant has a fair market net worth sufficient to sustain the risks inherent in the program, including loss of investment and lack of liquidity; and (c) the program is otherwise suitable for the participant; and (ii) maintain in the files of the member documents disclosing the basis upon which the determination of suitability was reached as to each participant. (C) Notwithstanding the provisions of subparagraphs (A) and (B) hereof, no member shall execute any transaction in a direct participation program in a discretionary account without prior written approval of the transaction by the customer. Sec. (b)(3) DISCLOSURE (A) Prior to participating in a public offering of a direct participation program, a member or person associated with a member shall have reasonable grounds to believe, based on information made available to him by the sponsor through a prospectus or other materials, that all material facts are adequately and accurately disclosed and provide a basis for evaluating the program. (B) In determining the adequacy of disclosed facts pursuant to subparagraph (A) hereof, a member or person associated with a member shall obtain information on material facts relating at a minimum to the following, if relevant in view of the nature of the program: (i) items of compensation; (ii) physical properties; (iii) tax aspects; (iv) financial stability and experience of the sponsor; Anthem Securities, Inc. 3 Selling Agent Agreement (v) the program's conflicts and risk factors; and (vi) appraisals and other pertinent reports. (C) For purposes of subparagraphs (A) and (B) hereof, a member or person associated with a member may rely upon the results of an inquiry conducted by another member or members, provided that: (i) the member or person associated with a member has reasonable grounds to believe that such inquiry was conducted with due care; (ii) the results of the inquiry were provided to the member or person associated with a member with the consent of the member or members conducting or directing the inquiry; and (iii) no member that participated in the inquiry is a sponsor of the program or an affiliate of such sponsor. (D) Prior to executing a purchase transaction in a direct participation program, a member or person associated with a member shall inform the prospective participant of all pertinent facts relating to the liquidity and marketability of the program during the term of investment. (f) You shall not offer or sell the Units in any jurisdiction until you have been advised in writing by the Managing General Partner, or the Managing General Partner's special counsel, that the offer or sale of the Units: (i) has been qualified in the jurisdiction; (ii) is exempt from the qualification requirements imposed by the jurisdiction; or (iii) the qualification is otherwise not required. (g) You have received copies of the Prospectus relating to the Units and you have relied only on the statements contained in the Prospectus and not on any other statements whatsoever, either written or oral, with respect to the details of the offering of Units. You shall deliver a copy of the Prospectus to each subscriber to whom you sell the Units at or before the completion of any sale of Units to such subscriber (which sale shall be deemed, for the purposes of this Agreement to occur on the date on which that subscriber delivers subscription funds to the escrow agent), or earlier if required by the blue sky or securities laws of any jurisdiction. Unless advised otherwise by the Managing General Partner, you may choose to provide each offeree with the following sales materials which are collectively referred to as the "Sales Literature": (i) a flyer entitled "Atlas America Public #14-2004 Program"; (ii) an article entitled "Tax Rewards with Oil and Gas Partnerships"; (iii) a brochure of tax scenarios entitled "How an Investment in Atlas America Public #14-2004 Program Can Help Achieve an Investor's Tax Objectives"; Anthem Securities, Inc. 4 Selling Agent Agreement (iv) a brochure entitled "Investing in Atlas America Public #14-2004 Program"; (v) a booklet entitled "Outline of Tax Consequences of Oil and Gas Drilling Programs"; (vi) a brochure entitled "The Appalachian Basin: A Prime Drilling Location Which Commands a Premium"; (vii) a brochure entitled "Investment Insights - Tax Time"; (viii) a brochure entitled "Frequently Asked Questions"; and (ix) possibly other supplementary materials. Any such Sales Literature, if distributed, must have been preceded or must be accompanied by the Prospectus. (h) You agree that you shall not place any advertisement or other solicitation with respect to the Units (including without limitation any material for use in any newspaper, magazine, radio or television commercial, telephone recording, motion picture, or other public media) without: (i) the prior written approval of the Managing General Partner; and (ii) the prior written approval of the form and content thereof by the Commission, the NASD and the securities authorities of the states where such advertisement or solicitation is to be circulated. Any such advertisements or solicitations shall be at your expense. (i) If a supplement or amendment to the Prospectus is prepared and delivered to you by the Managing General Partner or the Dealer-Manager, you agree as follows: (i) to distribute each supplement or amendment to the Prospectus to every person who has previously received a copy of the Prospectus from you; and (ii) to include each supplement or amendment in all future deliveries of any Prospectus. (j) In connection with any offer or sale of the Units, you agree to the following: (i) to comply in all respects with statements set forth in the Prospectus, the Partnership Agreement, and any supplements or amendments to the Prospectus; (ii) not to make any statement inconsistent with the statements in the Prospectus, the Partnership Agreement, and any supplements or amendments to the Prospectus; (iii) not to provide any written information, statements, or sales materials other than the Prospectus, the Sales Literature, and any supplements or amendments to the Prospectus unless approved in writing by the Managing General Partner; and (iv) not to make any untrue statement of a material fact or omit to state a material fact necessary in order to make statements made, in light of the circumstances under which they were made, not misleading in connection with the Partnerships, the Units or the offering. Anthem Securities, Inc. 5 Selling Agent Agreement (k) You agree to use your best efforts in the solicitation and sale of the Units, including that: (i) you comply with all the provisions of the Act, the Act of 1934, the applicable rules and regulations of the Commission, the applicable state securities laws and regulations, this Agreement, and the NASD Conduct Rules; (ii) the prospective purchasers meet the suitability requirements set forth in the Prospectus, the Subscription Agreement, and this Agreement; and (iii) the prospective purchasers properly complete and execute the Subscription Agreement, which has been provided as Exhibit (I-B) to the Partnership Agreement, Exhibit (A) of the Prospectus, together with any additional forms provided in any supplement or amendment to the Prospectus, or otherwise provided to you by the Managing General Partner or the Dealer-Manager to be completed by prospective purchasers. You acknowledge and agree that the Managing General Partner shall have the right to reject any subscription at any time for any reason without liability to it. Subscription funds and executed subscription packets shall be transmitted as set forth in Section 11 of this Agreement. (l) Although not anticipated, if you assist in any transfers of the Units, then you shall comply with the requirements of Rules 2810(b)(2)(B) and (b)(3)(D) of the NASD Conduct Rules. (m) You agree and covenant that: (i) the representations and warranties you make in this Agreement are and shall be true and correct as of the date of this Agreement and at the applicable closing date; and (ii) you shall and have fulfilled all your obligations under this Agreement at the applicable closing date. 2. COMMISSIONS. (a) Subject to the receipt of the minimum required subscription proceeds of $2,000,000 as described in Section 4(d) of the Dealer-Manager Agreement, and the discounts set forth in Section 4(c) of the Dealer-Manager Agreement for sales to the Managing General Partner, its officers, directors and affiliates, registered investment advisors and their clients, Selling Agents and their registered representatives and principals, and investors who buy Units through the officers or directors of the Managing General Partner, the Dealer-Manager is entitled to receive from the Managing General Partner a 7% Sales Commission and a .5% accountable Reimbursement for Permissible Non-Cash Compensation, based on the aggregate amount of all Unit subscriptions to a Partnership secured by the Dealer-Manager or the selling group formed by the Dealer-Manager and accepted by the Managing General Partner. The Permissible Non-Cash Compensation will be paid for training and education meetings, gifts that do not exceed $100 per year and are not preconditioned on the achievement of a sales target, an occasional meal, a ticket to a sporting event or the theater, or comparable entertainment which is neither so frequent nor so extensive as to raise any question of propriety and is not preconditioned on achievement of a sales target and contributions by the Dealer-Manager or Managing General Partner to a non-cash compensation arrangement between you and your associated persons, provided that the Dealer-Manager or Managing General Partner do not directly or indirectly participate in your organization of the permissible non-cash compensation arrangement. Anthem Securities, Inc. 6 Selling Agent Agreement Additionally, the Dealer-Manager is entitled to receive from the Managing General Partner an up to .5% reimbursement of the Selling Agents' bona fide accountable due diligence expenses per Unit. Subject to the terms and conditions set forth in this Agreement, including the Dealer-Manager's receipt from you of the documentation required of you in Section 1 of this Agreement, the Dealer-Manager agrees to pay you on Units sold by you and accepted by the Managing General Partner: (i) a 7% Sales Commission, subject to the performance by you of your obligations under Appendix I to this Agreement, which is incorporated in this Agreement by reference; and (ii) up to a .5% reimbursement of your bona fide accountable due diligence expenses per Unit. With respect to the up to .5% reimbursement of your bona fide accountable due diligence expenses, any bill presented by you to the Dealer-Manager for reimbursement of costs associated with your due diligence activities must be for actual costs and may not include a profit margin. Although the Dealer-Manager is not required to obtain an itemized expense statement before paying out due diligence expenses, any bill for due diligence submitted by you must be based on your actual expenses incurred in conducting due diligence. If the Dealer-Manager receives a non-itemized bill for due diligence that it has reason to question, then it has the obligation to ensure your compliance by requesting an itemized statement to support the bill submitted by you. If such a due diligence bill cannot be justified, any excess over actual due diligence expenses that is paid is considered by the NASD to be undisclosed underwriting compensation and is required to be included within the 10% compensation guideline under NASD Conduct Rule 2810, and reflected on your books and records. Notwithstanding, if you provide an itemized bill in excess of .5% then the excess over .5% will not be included within the 10% compensation guideline, but instead the 4.5% organization and offering cost guideline of NASD Conduct Rule 2810. (iii) In addition, the Dealer-Manager or Managing General Partner may make certain non-cash compensation arrangements of up to .5% per Unit with you or your registered representatives, which will be included in the accountable Reimbursement for Permissible Non-Cash Compensation of up to .5% per Unit. The Dealer-Manager is responsible for ensuring that all non-cash compensation arrangements comply with the restrictions on non-cash compensation in connection with direct participation programs as set forth in NASD Conduct Rule 2810. For example, if the Managing General Partner or Dealer-Manager pays or reimburses you in connection with meetings held by the Managing General Partner or Dealer-Manager for the purpose of training or education of your registered representatives, then the following conditions must be met: (A) your registered representative must obtain your prior approval to attend the meeting and attendance by your registered representatives must not be conditioned by you on the achievement of a sales target; (B) the location of the training and education meeting must be appropriate to the purpose of the meeting, as defined in NASD Conduct Rule 2810; Anthem Securities, Inc. 7 Selling Agent Agreement (C) the payment or reimbursement must not be applied to the expenses of guests of the registered representative; (D) the payment or reimbursement by the Managing General Partner or Dealer-Manager must not be conditioned by the Managing General Partner or Dealer-Manager on the achievement of a sales target; and (E) the appropriate records must be maintained. Non-cash compensation means any form of compensation received in connection with the sale of the Units that is not cash compensation, including but not limited to merchandise, gifts and prizes, travel expenses, meals and lodging. (iv) Your sales commissions which are owed to you as set forth above shall be paid to you within seven business days after the Dealer-Manager has received the related amounts owed to it under the Dealer-Manager Agreement, which the Dealer-Manager is entitled to receive within five business days after the conditions described in Section 4(e) of the Dealer-Manager Agreement are satisfied and approximately every two weeks thereafter until the respective Partnership's Offering Termination Date, which is described in Section 1 of the Dealer-Manager Agreement. The balance of your sales commissions and the reimbursements which are owed to you as set forth above shall be paid to you within seven business days after the Dealer-Manager has received the related amounts owed to it under the Dealer-Manager Agreement, which the Dealer-Manager is entitled to receive within fourteen business days after the respective Partnership's Offering Termination Date. (b) Notwithstanding anything in this Agreement to the contrary, you agree to waive payment of your compensation and reimbursements which are owed to you as set forth above until the Dealer-Manager is in receipt of the related amounts owed to it under the Dealer-Manager Agreement, and the Dealer-Manager's liability to pay your compensation and reimbursements under this Agreement shall be limited solely to the proceeds of the related amounts owed to it under the Dealer-Manager Agreement. (c) As provided in Section 4(d) of the Dealer-Manager Agreement, a Partnership shall not begin operations unless it receives subscription proceeds for at least $2,000,000 by its respective Offering Termination Date. If this amount is not secured by the respective Partnership's Offering Termination Date, then nothing shall be payable to you for the respective Partnership and all funds advanced by subscribers for Units in the respective Partnership shall be returned to them with interest earned, if any. 3. BLUE SKY QUALIFICATION. The Managing General Partner may elect not to qualify or register Units in any state or jurisdiction in which it deems the qualification or registration is not warranted for any reason in its sole discretion. On application to the Dealer-Manager you will be informed as to the states and jurisdictions in which the Units have been qualified for sale or are exempt under the respective securities or "Blue Sky" laws of those states and jurisdictions. Notwithstanding the foregoing, the Dealer-Manager, the Partnerships, and the Managing General Partner have not assumed and will not assume any obligation or responsibility as to your right to act as a broker/dealer with respect to the Units in any state or jurisdiction. 4. EXPENSE OF SALE. The expenses in connection with the offer and sale of the Units shall be payable as set forth below. Anthem Securities, Inc. 8 Selling Agent Agreement (a) The Dealer-Manager shall pay all expenses incident to the performance of its obligations under this Agreement, including the fees and expenses of its attorneys and accountants, even if the offering of any or all of the Partnerships is not successfully completed. (b) You shall pay all expenses incident to the performance of your obligations under this Agreement, including the fees and expenses of your own counsel and accountants, even if the offering of any or all of the Partnerships is not successfully completed. 5. CONDITIONS OF YOUR DUTIES. Your obligations under this Agreement, as of the date of this Agreement and at the applicable closing date, shall be subject to the following: (a) the performance by the Dealer-Manager of its obligations under this Agreement; and (b) the performance by the Managing General Partner of its obligations under the Dealer-Manager Agreement. 6. CONDITIONS OF DEALER-MANAGER'S DUTIES. The Dealer-Manager's obligations under this Agreement, including the duty to pay compensation and reimbursements to you as set forth in Section 2 of this Agreement, shall be subject to the following: (a) the accuracy, as of the date of this Agreement and at the applicable closing date as if made at the applicable closing date, of your representations and warranties made in this Agreement; (b) the performance by you of your obligations under this Agreement; and (c) the Dealer-Manager's receipt, at or before the applicable closing date, of a fully executed Subscription Agreement for each prospective purchaser as required by Section 1(k) of this Agreement. 7. INDEMNIFICATION. (a) You shall indemnify and hold harmless the Dealer-Manager, the Managing General Partner, each Partnership and its attorneys against any losses, claims, damages or liabilities, joint or several, to which they may become subject under the Act, the Act of 1934, or otherwise insofar as the losses, claims, damages, or liabilities (or actions in respect thereof) arise out of or are based on your breach of any of your duties and obligations, representations, or warranties under the terms or provisions of this Agreement, and you shall reimburse them for any legal or other expenses reasonably incurred in connection with investigating or defending the losses, claims, damages, liabilities, or actions. (b) The Dealer-Manager shall indemnify and hold you harmless against any losses, claims, damages, or liabilities, joint or several, to which you may become subject under the Act, the Act of 1934, or otherwise insofar as the losses, claims, damages, or liabilities (or actions in respect thereof) arise out of or are based on the Dealer-Manager's breach of any of its duties and obligations, representations, or warranties under the terms or provisions of this Agreement, and the Dealer-Manager shall reimburse you for any legal or other expenses reasonably incurred in connection with investigating or defending the losses, claims, damages, liabilities, or actions. Anthem Securities, Inc. 9 Selling Agent Agreement (c) The foregoing indemnity agreements shall extend on the same terms and conditions to, and shall inure to the benefit of, each person, if any, who controls each indemnified party within the meaning of the Act. (d) Promptly after receipt by an indemnified party of notice of the commencement of any action, the indemnified party shall, if a claim in respect of the action is to be made against the indemnifying party under this Section, notify the indemnifying party in writing of the commencement of the action; but the omission to promptly notify the indemnifying party shall not relieve the indemnifying party from any liability which it may have to the indemnified party. If any action is brought against an indemnified party, it shall notify the indemnifying party of the commencement of the action, and the indemnifying party shall be entitled to participate in, and, to the extent that it wishes, jointly with any other indemnifying party similarly notified, to assume the defense of the action, with counsel satisfactory to the indemnified and indemnifying parties. After the indemnified party has received notice from the agreed on counsel that the defense of the action under this paragraph has been assumed, the indemnifying party shall not be responsible for any legal or other expenses subsequently incurred by the indemnified party in connection with the defense of the action other than with respect to the agreed on counsel who assumed the defense of the action. 8. REPRESENTATIONS AND AGREEMENTS TO SURVIVE DELIVERY. All representations, warranties, and agreements of the Dealer-Manager and you in this Agreement, including the indemnity agreements contained in Section 7 of this Agreement, shall: (a) survive the delivery, execution and closing of this Agreement; (b) remain operative and in full force and effect regardless of any investigation made by or on behalf of you or any person who controls you within the meaning of the Act, by the Dealer-Manager, or any of its officers, directors or any person who controls the Dealer-Manager within the meaning of the Act, or any other indemnified party; and (c) survive delivery of the Units. 9. TERMINATION. (a) You shall have the right to terminate this Agreement other than the indemnification provisions of Section 7 of this Agreement by giving notice as specified in Section 16 of this Agreement any time at or before a closing date: (i) if the Dealer-Manager has failed, refused, or been unable at or before a closing date, to perform any of its obligations under this Agreement; or (ii) there has occurred an event materially and adversely affecting the value of the Units. (b) The Dealer-Manager may terminate this Agreement other than the indemnification provisions of Section 7 of this Agreement, for any reason and at any time, by promptly giving notice to you by telephone, e-mail, facsimile or telegram, confirmed by letter. 10. FORMAT OF CHECKS/ESCROW AGENT. Pending receipt of the minimum subscription proceeds of $2,000,000 as set forth in Section 4(d) of the Dealer-Manager Agreement, the Dealer-Manager and you, including if you are a customer carrying broker/dealer, agree that all subscribers shall be instructed to make their checks or wires payable solely to the Escrow Agent for the Partnership in which the Units are then being offered as follows: Anthem Securities, Inc. 10 Selling Agent Agreement (a) "Atlas Public #14-2004 L.P., Escrow Agent, National City Bank of PA"; (b) "Atlas Public #14-2005(A) L.P., Escrow Agent, National City Bank of PA"; or (c) "Atlas Public #14-2005(B) L.P., Escrow Agent, National City Bank of PA"; as agent for the respective Partnership then being offered. You, including if you are a customer carrying broker/dealer, agree to comply with Rule 15c2-4 adopted under the Act of 1934. In addition, for identification purposes, wire transfers should reference the subscriber's name and the account number of the escrow account for the Partnership in which the Units are then being offered. If you receive a check not conforming to the foregoing instructions, then you shall return the check directly to the subscriber not later than the end of the next business day following its receipt by you from the subscriber. If the Dealer-Manager receives a check not conforming to the foregoing instructions, then the Dealer-Manager shall return the check to you not later than the end of the next business day following its receipt by the Dealer-Manager and you shall then return the check directly to the subscriber not later than the end of the next business day following its receipt by you from the Dealer-Manager. Checks received by you which conform to the foregoing instructions shall be transmitted by you under Section 11 "Transmittal Procedures," below. You agree that you are bound by the terms of the Escrow Agreement, a copy of which is attached to the Dealer-Manager Agreement as Exhibit "A." 11. TRANSMITTAL PROCEDURES. You, including if you are a customer carrying broker/dealer, shall transmit received investor funds in accordance with the following procedures. (a) Pending receipt of a Partnership's minimum subscription proceeds of $2,000,000 as set forth in Section 4(d) of the Dealer-Manager Agreement, you shall promptly transmit any and all checks received by you from subscribers and the original executed Subscription Agreement to the Dealer-Manager by the end of the next business day following receipt of the check by you. By the end of the next business day following its receipt of the check and the original executed subscription documents, the Dealer-Manager shall transmit the check and a copy of the executed Subscription Agreement to the Escrow Agent, and the original executed Subscription Agreement and a copy of the check to the Managing General Partner. (b) On receipt by you of notice from the Managing General Partner or the Dealer-Manager that a Partnership's minimum subscription proceeds of $2,000,000 as set forth in Section 4(d) of the Dealer-Manager Agreement have been received, you agree that all subscribers then may be instructed, in the Managing General Partner's sole discretion, to make their checks or wires payable solely to the Partnership then being offered. Thereafter, you shall promptly transmit any and all checks received by you from subscribers and the original executed Subscription Agreement to the Dealer-Manager by the end of the next business day following receipt of the check by you. By the end of the next business day following its receipt of the check and original Subscription Agreement, the Dealer-Manager shall transmit the check and the original executed Subscription Agreement to the Managing General Partner. Anthem Securities, Inc. 11 Selling Agent Agreement 12. PARTIES. This Agreement shall inure to the benefit of and be binding on you, the Dealer-Manager, and any respective successors and assigns. This Agreement shall also inure to the benefit of the indemnified parties, their successors and assigns. This Agreement is intended to be and is for the sole and exclusive benefit of the parties to this Agreement, including their respective successors and assigns, and the indemnified parties and their successors and assigns, and for the benefit of no other person. No other person shall have any legal or equitable right, remedy or claim under or in respect of this Agreement. No purchaser of any of the Units from you shall be construed a successor or assign merely by reason of the purchase. 13. RELATIONSHIP. You are not authorized to hold yourself out as agent of the Dealer-Manager, the Managing General Partner, a Partnership or any other Selling Agent. This Agreement shall not constitute you a partner of the Managing General Partner, the Dealer-Manager, a Partnership, any general partner of a Partnership, or any other Selling Agent, nor render the Managing General Partner, the Dealer-Manager, the Partnerships, any general partner of a Partnership, or any other Selling Agent, liable for any of your obligations. 14. EFFECTIVE DATE. This Agreement is made effective between the parties as of the date accepted by you as indicated by your signature to this Agreement. 15. ENTIRE AGREEMENT, WAIVER. (a) This Agreement constitutes the entire agreement between the Dealer-Manager and you, and shall not be amended or modified in any way except by subsequent agreement executed in writing. Neither party to this Agreement shall be liable or bound to the other by any agreement except as specifically set forth in this Agreement. (b) The Dealer-Manager and you may waive, but only in writing, any term, condition, or requirement under this Agreement that is intended for its benefit. However, any written waiver of any term or condition of this Agreement shall not operate as a waiver of any other breach of the term or condition of this Agreement. Also, any failure to enforce any provision of this Agreement shall not operate as a waiver of that provision or any other provision of this Agreement. 16. NOTICES. (a) Any communications from you shall be in writing addressed to the Dealer-Manager at P.O. Box 926, Moon Township, Pennsylvania 15108-0926. (b) Any notice from the Dealer-Manager to you shall be deemed to have been duly given if mailed, faxed or telegraphed to you at your address shown below. 17. COMPLAINTS. The Dealer-Manager and you agree as follows: (a) to notify the other if either receives an investor complaint in connection with the offer or sale of Units by you; (b) to cooperate with the other in resolving the complaint; and (c) to cooperate in any regulatory examination of the other to the extent it involves this Agreement or the offer or sale of Units by you. 18. PRIVACY. The Dealer-Manager and you each acknowledge that certain information made available to the other under this Agreement may be deemed nonpublic personal information under the Gramm-Leach-Bliley Act, other federal or state privacy laws (as amended), and the rules and regulations promulgated thereunder, which are referred to collectively as the "Privacy Laws." The Dealer-Manager and you agree as follows: Anthem Securities, Inc. 12 Selling Agent Agreement (a) not to disclose or use the information except as required to carry out each party's respective duties under this Agreement or as otherwise permitted by law in the ordinary course of business; (b) to establish and maintain procedures reasonably designed to assure the security and privacy of all the information; and (c) to cooperate with the other and provide reasonable assistance in ensuring compliance with the Privacy Laws to the extent applicable to either or both the Dealer-Manager and you. 19. ANTI-MONEY LAUNDERING PROVISION. You represent and warrant to the Managing General Partner and the Dealer-Manager that you have in place and will maintain suitable and adequate "know your customer" policies and procedures and that you shall comply with all applicable laws and regulations regarding anti-money laundering activity and will provide such documentation to the Managing General Partner and the Dealer-Manager on written request. 20. ACCEPTANCE. Please confirm your agreement to become a Selling Agent under the terms and conditions set forth above by signing and returning the enclosed duplicate copy of this Agreement to us at the address set forth above. Sincerely, , 2004 ANTHEM SECURITIES, INC. - --------------------- Date ATTEST: By: - -------------------------- ------------------------------ (SEAL) Secretary Justin Atkinson, President Anthem Securities, Inc. 13 Selling Agent Agreement ACCEPTANCE: We accept your invitation to become a Selling Agent under all the terms and conditions stated in the above Agreement and confirm that all the statements set forth in the above Agreement are true and correct. We hereby acknowledge receipt of the Prospectuses and Sales Literature and a copy of the Dealer-Manager Agreement referred to above. , 2004 , - --------------------------- ----------------------------------------- Date a(n) ________________________corporation, ATTEST: By: - --------------------------------- ---------------------------------- (SEAL) Secretary _______________________, President ----------------------------------------- (Address) ----------------------------------------- ----------------------------------------- ----------------------------------------- (Telephone Number) Your CRD Number is ---------------------- Your Tax ID Number is ------------------- Anthem Securities, Inc. 14 Selling Agent Agreement APPENDIX I TO SELLING AGENT AGREEMENT In partial consideration for the payment to you, as Selling Agent, by the Dealer-Manager of the Sales Commission as set forth in Section 2(a) of the Selling Agent Agreement, you warrant, represent, covenant, and agree with the Dealer-Manager that you, as Selling Agent, shall do the following: o prominently and promptly announce your participation in the offering as Selling Agent to your registered representatives, whether by newsletter, e-mail, mail or otherwise, which announcement also shall advise your registered representatives to contact our Regional Marketing Director in whose territory the registered representative is located (the information concerning our Regional Marketing Directors has been provided to you by separate correspondence) with a copy of the announcement provided concurrently to the Dealer-Manager; and o provide the Dealer-Manager with the names, telephone numbers, addresses and e-mail addresses of your registered representatives, which information shall be kept confidential by the Dealer-Manager and the Managing General Partner and shall not be used for any purpose other than the marketing of the offering as set forth in the Dealer-Manager Agreement and the Selling Agent Agreement. Further, you, as Selling Agent, agree that the Dealer-Manager and the Managing General Partner may directly contact your registered representatives, in person or otherwise, to: o inform them of the offering; o explain the merits and risks of the offering; and o otherwise assist in your registered representatives' efforts to solicit and sell Units. Anthem Securities, Inc. 15 Selling Agent Agreement EX-1 3 ex-1c.txt EXHIBIT 1(C) EXHIBIT 1(C) ATLAS AMERICA PUBLIC #14-2004 PROGRAM SELECTED INVESTMENT ADVISOR AGREEMENT SELECTED INVESTMENT ADVISOR AGREEMENT TABLE OF CONTENTS
PAGE 1. Description of Units..................................................................................1 2. Representations, Warranties and Agreements of the Managing General Partner............................2 3. Purchase of Units.....................................................................................3 4. No Compensation to SIA................................................................................8 5. Association of the Partnerships with Other Advisors and Dealers.......................................8 6. Conditions of the SIA's Obligations...................................................................8 7. Conditions to the Managing General Partner's Obligations..............................................8 8. Covenants of the SIA..................................................................................9 9. Covenants of the Managing General Partner.............................................................9 10. Payment of Costs and Expenses........................................................................10 11. Indemnification......................................................................................10 12. Representations and Agreements to Survive Delivery...................................................11 13. Term of Agreement....................................................................................11 14. Notices..............................................................................................11 15. Successors...........................................................................................12 16. Miscellaneous........................................................................................12
EXHIBIT A TO SELECTED INVESTMENT ADVISOR AGREEMENT OF ATLAS AMERICA PUBLIC #14-2004 PROGRAM i SELECTED INVESTMENT ADVISOR AGREEMENT RE: ATLAS AMERICA PUBLIC #14-2004 PROGRAM ------------------------------------- THIS SELECTED INVESTMENT ADVISOR AGREEMENT, which is referred to as the "Agreement" is made and entered into as of the day indicated on Exhibit A attached to this Agreement and by this reference incorporated in this Agreement, between Atlas Resources, Inc., which is referred to as the "Managing General Partner," on behalf of Atlas America Public #14-2004 Program, and the selected investment advisor (the "SIA") identified in Exhibit A to this Agreement. 1. DESCRIPTION OF UNITS. (a) Atlas America Public #14-2004 Program, which is referred to as the "Program," is a series of up to three limited partnerships organized or to be organized under the laws of Delaware as described below. These limited partnerships are sometimes referred to in this Agreement in the singular as a "Partnership" or in the plural as "Partnerships." The Partnerships will be named as follows: (i) Atlas America Public #14-2004 L.P.; (ii) Atlas America Public #14-2005(A) L.P.; and (iii) Atlas America Public #14-2005(B) L.P. On behalf of the Program and the Partnerships, a Registration Statement on Form S-1 (Registration No. __________) relating to the offer and sale of the limited partner interests and the investor general partner interests in the Partnerships, which are collectively referred to as the "Units," was filed on June ___, 2004, with the Securities and Exchange Commission (the "Commission") under the Securities Act of 1933, as amended, which is referred to as the "Act." The Registration Statement has been declared effective by the Commission and the Partnerships and the Units are described in the Prospectus (the "Prospectus") that forms a part of the Registration Statement. As used in this Agreement, the terms "Prospectus" and "Registration Statement" refer solely to the Prospectus and Registration Statement, as amended, described above, except that: (i) from and after the date on which any post-effective amendment to the Registration Statement is declared effective by the Commission, the term "Registration Statement" shall refer to the Registration Statement as amended by that post-effective amendment, and the term "Prospectus" shall refer to the Prospectus then forming a part of the Registration Statement; and (ii) if the Prospectus filed by the Managing General Partner under Rule 424(b) or (c) promulgated by the Commission under the Act differs from the Prospectus on file with the Commission at the time the Registration Statement or any post-effective amendment to the Registration Statement becomes effective, the term "Prospectus" shall refer to the Prospectus filed under that Rule from and after the date on which it was filed. 1 Terms defined in the Prospectus and not otherwise defined in this Agreement shall have the meanings set forth in the Prospectus. (b) Generally, the Units will be sold at a price of $10,000 per Unit subject to the discounts set forth in Section 3 of this Agreement for clients of the SIA. Subject to the receipt and acceptance by the Managing General Partner of the minimum subscription proceeds of $2,000,000 in a Partnership by its Offering Termination Date as described in the Prospectus (the "Offering Termination Date"), the Managing General Partner may break escrow and use the subscription proceeds for the Partnership's drilling activities, which is referred to as the "Initial Closing Date." The subscription period for each Partnership will be as described in the Prospectus. However, the offering of Atlas America Public #14-2004 L.P. may not extend beyond December 31, 2004, the offering of Atlas America Public #14-2005(A) L.P. may not extend beyond May 31, 2005, and the offering of Atlas America Public #14-2005(B) L.P. may not extend beyond December 31, 2005. Also, the maximum subscription proceeds of all of the Partnerships, in the aggregate, must not exceed the registered amount of the Program of $125 million. The Managing General Partner will notify the SIA of the Initial Closing Date and Offering Termination Date for each Partnership. 2. REPRESENTATIONS, WARRANTIES AND AGREEMENTS OF THE MANAGING GENERAL PARTNER. The Managing General Partner represents and warrants to and agrees with you that: (a) The Partnerships composing the Program have a currently effective Registration Statement on Form S-1, including a final Prospectus, for the registration of the Units under the Act as described in Section 1 of this Agreement. (b) The Managing General Partner shall provide to you for delivery to all offerees and purchasers and their representatives the information and documents that the Managing General Partner deems appropriate to comply with the Act and applicable state securities acts, which are referred to as the "Blue Sky" laws. (c) The Units when issued will be duly authorized and validly issued as set forth in the Amended and Restated Certificate and Agreement of Limited Partnership of each Partnership, which is referred to as the "Partnership Agreement," the form of which is included as Exhibit (A) to the Prospectus, and subject only to the rights and obligations set forth in the Partnership Agreement or imposed by the laws of the state of formation of each Partnership or of any jurisdiction to the laws of which each Partnership is subject. (d) Each Partnership was or will be duly formed under the laws of the State of Delaware and once formed is or will be validly existing as a limited partnership in good standing under the laws of Delaware with full power and authority to own its properties and conduct its business as described in the Prospectus. Each Partnership will be qualified to do business as a limited partnership or similar entity offering limited liability in those jurisdictions where the Managing General Partner deems the qualification necessary to assure limited liability of the limited partners. (e) The Prospectus, as supplemented or amended, does not contain an untrue statement of a material fact or omit to state any material fact necessary in order to make the statements in the Prospectus, in the light of the circumstances under which they are made, not misleading. 2 3. PURCHASE OF UNITS. (a) The SIA represents and warrants and agrees with the Managing General Partner that it is: (i) an entity, as designated in Exhibit A to this Agreement; (ii) organized and presently in good standing in the state or states designated in Exhibit A to this Agreement; and (iii) presently registered as an investment advisor under the Investment Advisers Act of 1940, as amended, and presently registered or licensed as an investment advisor by the appropriate regulatory agency of each state in which the SIA has clients, or it is exempt from those registration requirements. (b) Subject to the terms and conditions set forth in this Agreement, the Managing General Partner hereby makes available for purchase by the clients of the SIA a portion of the Units. The SIA hereby covenants, warrants and agrees that, in regard to any purchase of the Units by its clients, it will comply with: (i) this Agreement; (ii) all of the terms and conditions of the Prospectus; and (iii) all applicable state and federal laws, including the Securities Exchange Act of 1934, as amended, the Investment Advisers Act of 1940, as amended, and any and all regulations and rules pertaining to those laws, issued before or after the date of this Agreement by the SEC. The SIA further agrees to the following: (i) to comply in all respects with the statements set forth in the Prospectus, the Partnership Agreement, and any supplements or amendments to the Prospectus; (ii) not to make any statement inconsistent with the statements in the Prospectus, the Partnership Agreement, and any supplements or amendments to the Prospectus; (iii) not to make any untrue statement of a material fact or omit to state a material fact necessary in order to make statements made, in light of the circumstances under which they were made, not misleading in connection with the Partnerships, the Units or the offering; and (iv) not to provide any written information, statements, or sales materials other than the Prospectus, the sales literature, and any supplements or amendments to the Prospectus provided to the SIA by the Managing General Partner unless approved in writing by the Managing General Partner. (c) Clients of the SIA may, following receipt of written notice by the SIA from the Managing General Partner of the effective date of the Registration Statement, purchase the Units in accordance with the terms contained in the Registration Statement and the Prospectus. The SIA shall comply with all requirements set forth in the Registration Statement and the Prospectus. The SIA shall use and distribute, in connection with the Units, only the Prospectus and sales literature which conforms in all respects to any restrictions of local law and the applicable requirements of the Act, and which has been approved in writing by the Managing General Partner. Any permitted sales literature, if distributed, must have been preceded by, or must be accompanied by, the Prospectus. The Managing General Partner reserves the right to establish additional procedures as it deems necessary to ensure compliance with the requirements of the Registration Statement, and the SIA shall comply with all of those additional procedures to the extent that it has received written notice of them. 3 (d) Pending receipt of the minimum subscription proceeds of $2,000,000 of a Partnership, all monies received for purchase of any of the Units shall be forwarded by the SIA to the Managing General Partner for delivery to National City Bank of Pennsylvania (the "Escrow Agent"), where the monies will be deposited in an escrow account established by the Managing General Partner solely for the subscriptions, except that, until the time (if any) that the monies are deliverable to the Managing General Partner under the Escrow Agreement between the Managing General Partner and the Escrow Agent, the SIA shall return directly to the subscriber who submitted the check any check not made payable to: (i) "Atlas America Public #14-2004 L.P., Escrow Agent, National City Bank of PA"; (ii) "Atlas America Public #14-2005(A) L.P., Escrow Agent, National City Bank of PA"; or (iii) "Atlas America Public #14-2005(B) L.P., Escrow Agent, National City Bank of PA." Subscriptions shall be executed as described in the Registration Statement or as directed by the Managing General Partner. The SIA shall deliver the check and the original subscription documents to the Managing General Partner no later than the close of business of the first business day after receipt of the check and the subscription documents by the SIA. (e) During the term of this Agreement the Managing General Partner shall have full authority to take any action as it deems advisable in respect to all matters pertaining to the performance of the SIA under this Agreement. (f) The Units may be purchased by clients of the SIA: (i) only where the Units may be legally offered and sold; (ii) only by persons in those states who are legally qualified to purchase the Units; and (iii) only by persons in those states in which the SIA is registered as an investment advisor or exempt from any applicable registration requirements. (g) The SIA shall have no obligation under this Agreement to advise its clients to purchase any of the Units. (h) The SIA shall use every reasonable effort to assure that Units are purchased only by investors who: (i) meet the investor suitability standards, including the minimum income and net worth standards established by the Managing General Partner and set forth in the Prospectus, and the minimum purchase requirements set forth in the Prospectus; 4 (ii) can reasonably benefit from an investment in the Partnership based on each prospective investor's overall investment objectives and portfolio structure; (iii) are able to bear the economic risk of the investment based on each prospective investor's overall financial situation; (iv) have an apparent understanding of: (1) the fundamental risks of the investment; (2) the risk that the prospective investor may lose the entire investment; (3) the lack of liquidity of the Units; (4) the restrictions on transferability of the Units; (5) the background and qualifications of the employees and agents of the Managing General Partner; and (6) the tax consequences of an investment in the Units; and (v) the SIA will make the determinations required to be made by it under this subparagraph (h) based on information it obtains from each prospective investor, including, at a minimum, but not limited to, the prospective investor's: (1) age; (2) investment objectives; (3) investment experience; (4) income; (5) net worth; (6) financial situation; (7) other investments of the prospective investor; and (8) any other pertinent factors deemed by the SIA to be relevant. (i) In addition to complying with the provisions of subparagraph (h) above, and not in limitation of any other obligations of the SIA to determine suitability imposed by state or federal law, the SIA agrees that it will comply fully with the following provisions: (i) the SIA shall have reasonable grounds to believe, based on information provided by the investor concerning his investment objectives, other investments, financial situation and needs, and on any other information known by the SIA, that: (1) each client of the SIA who purchases Units is or will be in a financial position appropriate to enable him to realize to a significant extent the benefits (including tax benefits) of an investment in the Units; 5 (2) each client of the SIA that purchases Units has a fair market net worth sufficient to sustain the risks inherent in an investment in the Units (including the potential loss of his entire investment, and the lack of liquidity of the Units); and (3) the Units otherwise are or will be a suitable investment for each client of the SIA that purchases Units; and the SIA shall maintain files disclosing the basis on which the determination of suitability was made; (ii) the SIA shall not execute any transaction involving the purchase of Units in a discretionary account without prior written approval of the transactions by the investor; (iii) the SIA shall have reasonable grounds to believe, based on the information made available to it, that all material facts are adequately and accurately disclosed in the Registration Statement and provide a basis for evaluating the Units; (iv) in making the determination set forth in subparagraph (iii) above, the SIA shall evaluate items of compensation, physical properties, tax aspects, financial stability and experience of the sponsor, conflicts of interest and risk factors, appraisals, as well as any other information deemed pertinent by it; and (v) the SIA shall inform each prospective investor of all pertinent facts relating to the liquidity and marketability of the Units. (j) The SIA agrees to retain in its files, for a period of at least six years, information which will establish that each purchaser of Units falls within the permitted class of investors described in the Prospectus. (k) The SIA either: (i) shall not purchase Units for its own account; or (ii) shall hold any Units purchased for its own account for investment. (l) The SIA confirms that it is familiar with Securities Act Release No. 4968 and Rule 15c2-8 under the Securities Exchange Act of 1934, as amended, relating to the distribution of preliminary and final prospectuses, and that it has complied and will comply with them. (m) The SIA shall deliver a copy of Section 260.141.11 of the California Corporate Securities Law of 1968 to each client of the SIA that purchases Units and resides in California. (n) A sale of Units shall be deemed to be completed only after the Managing General Partner receives a properly completed Subscription Agreement for the Units from the SIA evidencing the fact that the investor had received a final Prospectus for a period of not less than five full business days, together with payment of the full purchase price of each purchased Unit from a buyer who satisfies each of the terms and conditions of the Registration Statement and Prospectus, and only after the Subscription Agreement has been accepted in writing by the Managing General Partner. 6 (o) Clients of the SIA who have been advised by the SIA on an ongoing basis regarding investments other than in a Partnership, and who are not being charged by the SIA, through the payment of commissions or otherwise, direct transaction based fees in connection with the purchase of the Units, shall purchase the Units net of the 7% Sales Commissions, at a purchase price of $9,300 per Unit. (p) The SIA shall not offer or sell the Units in any state until the SIA has been advised in writing by the Managing General Partner or the Managing General Partner's special counsel that the offer or sale of the Units: (i) has been qualified in the state; (ii) is exempt from the qualification requirements imposed by the state; or (iii) qualification in the state is otherwise not required. (q) The SIA confirms that it has received copies of the Prospectus relating to the Units and the SIA has relied only on the statements contained in the Prospectus and not on any other statements whatsoever, either written or oral, with respect to the details of the offering of Units. (r) The SIA agrees that it shall not place any advertisement or other solicitation with respect to the Units (including without limitation any material for use on the Internet or in any newspaper, magazine, radio or television commercial, telephone recording, motion picture, or other public media) without: (i) the prior written approval of the Managing General Partner; and (ii) the prior written approval of the form and content of the advertisement or solicitation by the Commission, the National Association of Securities Dealers, Inc. (the "NASD") and the securities authorities of the states where the advertisement or solicitation is to be circulated. Any of these advertisements or solicitations shall be at the SIA's expense. (s) If a supplement or amendment to the Prospectus is prepared and delivered to the SIA by the Managing General Partner or the Dealer-Manager, the SIA agrees as follows: (i) to distribute the supplement or amendment to every person who has previously received a copy of the Prospectus from the SIA; and (ii) to include the supplement or amendment in all future deliveries of the Prospectus. (t) The SIA agrees to use its best efforts in the solicitation and sale of the Units, including that the prospective purchasers properly complete and execute the Subscription Agreement, which has been provided as Exhibit (I-B) to the Partnership Agreement, Exhibit (A) of the Prospectus, together with any additional forms provided in any supplement or amendment to the Prospectus, or otherwise provided to the SIA by the Managing General Partner to be completed by prospective purchasers. (u) The SIA agrees and covenants that: 7 (i) the representations and warranties the SIA makes in this Agreement will be true and correct at the applicable closing date; and (ii) the SIA will have fulfilled all of its obligations under this Agreement at the applicable closing date. 4. NO COMPENSATION TO SIA. The Managing General Partner and the Program shall pay no fees, commissions, or other compensation to the SIA. 5. ASSOCIATION OF THE PARTNERSHIPS WITH OTHER ADVISORS AND DEALERS. It is expressly agreed between the Managing General Partner and the SIA that the Managing General Partner, the Dealer-Manager, and/or the Partnerships may cooperate with broker/dealers who are registered as broker/dealers with the NASD or with other investment advisors registered under the Investment Advisers Act of 1940, as amended. These broker/dealers and investment advisors may enter into agreements with the Managing General Partner, the Dealer-Manager, and/or the Partnerships on terms and conditions identical or similar to this Agreement and shall receive commissions or other fees as are agreed to between the Managing General Partner, the Dealer-Manager, and/or the Partnerships and the respective broker/dealers and investment advisors as are in accordance with the terms of the Registration Statement. 6. CONDITIONS OF THE SIA'S OBLIGATIONS. The SIA's obligations under this Agreement are subject, during the term of this Agreement and the offering, to: (a) the performance by the Managing General Partner of its obligations under this Agreement and compliance by the Managing General Partner with the covenants set forth in Section 9 of this Agreement; and (b) the conditions that: (i) the Registration Statement has become and remains effective; and (ii) no stop order has been issued suspending the effectiveness of the offering. 7. CONDITIONS TO THE MANAGING GENERAL PARTNER'S OBLIGATIONS. The obligations of the Managing General Partner under this Agreement are subject, during the term of this Agreement and the offering, to the conditions that: (a) at the effective date of the Registration Statement and during the term of this Agreement while any Units remain unsold, the Registration Statement remains in full force and effect authorizing the offer and sale of the Units; (b) no stop order suspending the effectiveness of the offering or other order restraining the offer or sale of the Units has been issued nor have proceedings for these orders been initiated or threatened by any state regulatory agency or the SEC; and (c) the SIA has satisfactorily performed all of its obligations under this Agreement and complied with the covenants set forth in Section 8 of this Agreement. 8. COVENANTS OF THE SIA. The SIA covenants, warrants and represents, during the term of this Agreement, that: 8 (a) the SIA is registered as an investment advisor under the Investment Advisers Act of 1940, as amended, and is registered or licensed as an investment advisor by the appropriate regulatory agency of each state in which the advisor has clients, or it is exempt from those registration requirements; (b) neither the SIA nor any person associated with the SIA is registered as a broker/dealer or registered representative with the NASD; (c) the SIA shall comply with all applicable federal and state securities laws, including, without limitation, the disclosure requirements of the Investment Advisers Act of 1940, as amended, and its provisions requiring disclosure of the existence of this Agreement and the compensation to be paid to the SIA under this Agreement; and (d) the SIA shall maintain the records in the form and for the periods required by Section 204 of the Investment Advisers Act of 1940, as amended, and Rule 204-2 under that act. 9. COVENANTS OF THE MANAGING GENERAL PARTNER. The Managing General Partner covenants, warrants and represents, during the term of this Agreement, that: (a) it will use its best efforts to maintain the effectiveness of the Registration Statement and to file all applications or amendments to the Registration Statement as may be reasonably necessary for that purpose; (b) it will inform the SIA whenever and as soon as it receives or learns of any order issued by the SEC, any state regulatory agency or any other regulatory agency which suspends the effectiveness of the Registration Statement or prevents the use of the Prospectus or which otherwise prevents or suspends the offering or sale of the Units, or receives notice of any proceedings regarding any order that would do so; (c) it will use its best efforts to prevent the issuance of any order described in subparagraph (b) above, and to lift the order if issued; (d) it will give the SIA written notice when the Registration Statement becomes effective and will deliver to the SIA the number of copies of the Prospectus, and any supplements and amendments to the Prospectus, which are finally approved by the SEC, as the SIA may reasonably request for sale of the Units; (e) it will promptly notify the SIA of any post-effective amendments or supplements to the Registration Statement or Prospectus, and will furnish the SIA with copies of any revised Prospectus and/or supplements and amendments to the Prospectus; (f) it will keep the SIA fully informed of any material development to which the Partnerships are a party or which concerns the business and condition of the Partnerships; and (g) it will use its best efforts to cause, at or before the time the Registration Statement becomes effective, the qualification of the Units for offer and sale under the securities laws of the states that the Partnerships elect. 10. PAYMENT OF COSTS AND EXPENSES. The SIA shall pay all costs and expenses incident to the performance of its obligations under this Agreement. 9 11. INDEMNIFICATION. (a) The SIA shall indemnify and hold harmless the Managing General Partner, each Partnership and its attorneys against any losses, claims, damages or liabilities, joint or several, to which they may become subject under the Securities Exchange Act, the Act of 1934, as amended, or otherwise insofar as the losses, claims, damages, or liabilities (or actions in respect thereof) arise out of or are based on the SIA's breach of any of its duties and obligations, representations, or warranties under the terms or provisions of this Agreement (including but not limited to an untrue statement or alleged untrue statement of a material fact, or any omission or alleged omission of a material fact, other than a statement, omission, or alleged statement or omission by the SIA which is also, as the case may be, contained in or omitted from the Prospectus or the Registration Statement or which was not based on information supplied to the Managing General Partner by the SIA) or the negligence, malpractice or malfeasance of the SIA; and the SIA shall reimburse them for any legal or other expenses reasonably incurred by them in connection with investigating or defending the losses, claims, damages, liabilities, or actions. (b) The Managing General Partner shall indemnify and hold the SIA harmless against any losses, claims, damages or liabilities, joint or several, to which the SIA may become subject under the Act, the Securities Exchange Act of 1934, as amended, or otherwise insofar as the losses, claims, damages, or liabilities (or actions in respect thereof) arise out of or are based on the Managing General Partner's breach of any of its duties and obligations, representations, or warranties under the terms or provisions of this Agreement, and the Managing General Partner shall reimburse the SIA for any legal or other expenses reasonably incurred by it in connection with investigating or defending the losses, claims, damages, liabilities, or actions. (c) The foregoing indemnity agreements shall extend on the same terms and conditions to, and shall inure to the benefit of, each person, if any, who controls each indemnified party within the meaning of the Act. (d) Promptly after receipt by an indemnified party of notice of the commencement of any action, the indemnified party shall, if a claim in respect of the action is to be made against an indemnifying party under this Section, notify the indemnifying party in writing of the commencement of the action; but the omission to promptly notify the indemnifying party shall not relieve the indemnifying party from any liability which it may have to any indemnified party. If any action is brought against an indemnified party, it shall notify the indemnifying party of the commencement of the action, and the indemnifying party shall be entitled to participate in, and, to the extent that it wishes, jointly with any other indemnifying party similarly notified, to assume the defense of the action, with counsel satisfactory to the indemnified and indemnifying parties. After the indemnified party has received notice from the agreed on counsel that the defense of the action under this paragraph has been assumed, the indemnifying party shall not be responsible for any legal or other expenses subsequently incurred by the indemnified party in connection with the defense of the action other than with respect to the agreed on counsel who assumed the defense of the action. 12. REPRESENTATIONS AND AGREEMENTS TO SURVIVE DELIVERY. All representations, warranties, and agreements of the Managing General Partner and the SIA in this Agreement, including the indemnity agreements contained in Section 11 of this Agreement, shall: 10 (a) survive the delivery, execution and closing of this Agreement; (b) remain operative and in full force and effect regardless of any investigation made by or on behalf of the SIA or any person who controls the SIA within the meaning of the Act, or by the Managing General Partner, or any of its officers or directors, or any person who controls the Managing General Partner within the meaning of the Act, or any other indemnified party; and (c) survive delivery of the Units. 13. TERM OF AGREEMENT. (a) This Agreement shall become effective on the date on which this Agreement is executed by the Managing General Partner and the SIA. The SIA and the Managing General Partner may each prevent this Agreement from becoming effective, without liability to the other, by written notice before the time this Agreement otherwise would become effective. (b) After this Agreement becomes effective, either party may terminate it at any time for any reason by giving 30 days' written notice to the other party; provided, however, that this Agreement shall in any event automatically terminate at the first occurrence of any of the following events: (i) the Registration Statement for the offer and sale of the Units ceases to be effective; (ii) the offering is terminated; or (iii) the SIA's license or registration to act as an investment advisor is revoked or suspended by any federal, self-regulatory or state agency and the revocation or suspension is not cured within 10 days from the date of the occurrence. In any event, this Agreement shall be deemed suspended during any period for which the SIA's license is revoked or suspended. 14. NOTICES. (a) All notices or communications under this Agreement, except as otherwise specifically provided in this Agreement, shall be in writing. (b) Any notice or communication sent by the Managing General Partner to the SIA shall be mailed, delivered, or sent by facsimile, e-mail or telegraph, and confirmed to the SIA to the person whose name and address are identified in Exhibit A to this Agreement. (c) Any notice or communication sent by the SIA to the Managing General Partner or the Partnership shall be mailed, delivered, or sent by facsimile, e-mail or telegraph, and confirmed at 311 Rouser Road, Moon Township, Pennsylvania 15108. 15. SUCCESSORS. This Agreement shall be binding on and inure to the benefit of the parties to this Agreement, and shall not be assigned or transferred by the SIA by operation of law or otherwise. 11 16. MISCELLANEOUS. (a) This Agreement shall be construed in accordance with the applicable laws of the Commonwealth of Pennsylvania. (b) Nothing in this Agreement shall constitute the SIA as in association with or in partnership with the Managing General Partner or the Partnerships. (c) This Agreement, including Exhibit A to this Agreement, embodies the entire understanding between the parties to the Agreement, and no variation, modification or amendment to this Agreement shall be deemed valid or effective unless it is in writing and signed by both parties to this Agreement. (d) If any provision of this Agreement is deemed void, invalid or ineffective for any reason, the remainder of this Agreement shall remain in full force and effect. (e) This Agreement may be executed in counterpart copies, each of which shall be deemed an original but all of which together shall constitute one and the same instrument comprising this Agreement. IN WITNESS WHEREOF, the parties have executed this Agreement on the date and year indicated on Exhibit A to this Agreement. SELECTED INVESTMENT ADVISOR PROGRAM ___________________________ ATLAS AMERICA PUBLIC #14-2004 PROGRAM (Name of SIA) By: Atlas Resources, Inc. Managing General Partner By:__________________________________ By: __________________________________ Print Name:_______________________ Jack L. Hollander, Senior Vice Title:_______________________________ President - Direct Participation Programs Witness:_____________________________ 12 EXHIBIT A TO SELECTED INVESTMENT ADVISOR AGREEMENT OF ATLAS AMERICA PUBLIC #14-2004 PROGRAM This Exhibit A is attached to and made a part of that certain Selected Investment Advisor Agreement, by and between Atlas Resources, Inc., which is referred to as the "Managing General Partner," on behalf of Atlas America Public #14-2004 Program and the Partnerships, and___________________________________ _____________________________________________________________, as the RIA. 1. Date of Agreement:__________________________________________________________ 2. Identity of RIA:____________________________________________________________ Name:_______________________________________________________________________ Type of Entity:_____________________________________________________________ (To be completed by the RIA, e.g., corporation, partnership or sole proprietorship.) State Organized in:_________________________________________________________ (To be completed by RIA.) Qualified To Do Business and in Good Standing in the Following Jurisdictions (including your state of organization). (Note: Qualification to do business in any jurisdiction is generally a requirement imposed by the secretary of state or other authority of jurisdictions in which you do business, and is not related to your holding a license as an investment advisor in those jurisdictions. Questions concerning this matter should be directed to your legal counsel.) _______________________________________________________________________________ _______________________________________________________________________________ (To be completed by the RIA.) Registered as an Investment Advisor in the following States: _______________________________________________________________________________ _______________________________________________________________________________ (To be completed by the RIA.) A-1 3. Name and Address for Notice Purposes (see Paragraph 14 of the Agreement): Name:_______________________________________________________________________ Title:______________________________________________________________________ Company:____________________________________________________________________ Address:____________________________________________________________________ City, State and Zip Code:___________________________________________________ Telephone Number (including area code):_____________________________________ 4. Please complete the following for our records: (a) How many registered investment advisors are with your firm?_____________ PLEASE ENCLOSE A CURRENT LIST. ALL INFORMATION WILL BE HELD IN CONFIDENCE. (b) Does your firm publish a newsletter? Yes___ No___ What is/are the frequency of the publication(s)? ___ Weekly ___ Monthly ___ Quarterly ___ Bi-weekly ___ Bi-monthly ___ Other (please specify) PLEASE PLACE JHollander@atlasamerica.com ON YOUR MAILING LIST AND PROVIDE A SAMPLE OF THE PUBLICATION IF AVAILABLE. (c) Does your firm have regular internal mailings, or bulk package mailings to its registered investment advisors? Yes___ No___ PLEASE PLACE JHollander@atlasamerica.com ON YOUR MAILING LIST AND PROVIDE A SAMPLE OF THE PUBLICATION IF AVAILABLE. (d) Does your firm have a computerized electronic mail (E-Mail) system for your registered investment advisors? Yes___ No___ If so, please provide e-mail address:___________________________________ (e) Website address:________________________________________________________ Person responsible:_____________________________________________________ A-2 EX-3 4 ex3-a.txt EXHIBIT 3(A) Exhibit 3(a) ARTICLES OF INCORPORATION OF ATLAS RESOURCES, INC. Commonwealth of Pennsylvania Department of State To All to Whom These Presents Shall Come, Greeting: Whereas, Under the provisions of the Business Corporation Law, approved the 5th day of May, Anno Domini one thousand nine hundred and thirty-three, P.L. 364, as amended, the Department of State is authorized and required to issue a CERTIFICATE OF INCORPORATION evidencing the incorporation of a business corporation organized under the terms of that law, and Whereas, The stipulations and conditions of that law have been fully complied with by the persons desiring to incorporate as ATLAS RESOURCES, INC. Therefore, Know Ye, That subject to the Constitution of this Commonwealth and under the authority of the Business Corporation Law, I do by these presents, which I have caused to be sealed with the Great Seal of the Commonwealth, create, erect, and incorporate the incorporators of and the subscribers to the shares of the proposed corporation named above, their associates and successors, and also those who may thereafter become subscribers or holders of the shares of such corporation, into a body politic and corporate in deed and in law by the name chosen hereinbefore specified, which shall exist perpetually and shall be invested with and have and enjoy all the powers, privileges, and franchises incident to a business corporation and be subject to all the duties, requirements, and restrictions specified and enjoined in and by the Business Corporation Law and all other applicable laws of this Commonwealth. Given under my Hand and the Great Seal of the Commonwealth, at the City of Harrisburg, this 9th day of July in the year of our Lord one thousand nine hundred and seventy-nine and of the Commonwealth the two hundred and fourth /s/ Ethel D. Allen, D.O. ------------------------------- Secretary of the Commonwealth _SC8:8CL-204 (Rev. 8-72) ------------------------------- Filing Fee: $75 Filed this 9th day of July, 1979, A18-7 Commonwealth of Pennsylvania Department of State Articles of /s/ Ethel D. Allen, D.O. Incorporation- Domestic Business Corporation Secretary of the Commonwealth ------------------------------- 79:37 617 6888825 COMMONWEALTH OF PENNSYLVANIA DEPARTMENT OF STATE CORPORATION BUREAU In compliance with the requirements of section 204 of the Business Corporation Law, act of of May 5, 1933 (P.L. 364) (15 P.S. Section 1204) the undersigned desiring to be incorporated as a business corporation, hereby certifies (certify) that: 1. The Name of the corporation is ATLAS RESOURCES, INC. 2. The location and post office address of the initial registered office of the corporation in this Commonwealth is: 311 Rouser Road, Coraopolis, Pennsylvania 15108. 3. The corporation is incorporated under the Business Corporation Law of the Commonwealth of Pennsylvania for the following purpose or purposes: To engage in and do any lawful act concerning any or all lawful business for which corporations may be incorporated under this act. 4. The term for which the corporation is to exist is perpetual. 5. The aggregate number of shares which the corporation shall have authority to issue is: Five Hundred (500) shares of capital stock without par value. 6. The name and post office address of each incorporator and the number and class of shares subscribed by such incorporator(s) is(are):
Number and Name Address Class of Shares Ira S. Pimm, Jr. 2225 Land Title Building 1 Philadelphia, PA 19110
IN TESTIMONY WHEREOF, the incorporator(s) has (have) signed and sealed these Articles of Incorporation this 5th day July, 1979.
Ira S.Pimm, Jr. _______________________________(SEAL) _______________________________(SEAL) _______________________________(SEAL)
COMMONWEALTH OF PENNSYLVANIA DEPARTMENT OF STATE CORPORATION BUREAU Articles of Incorporation Domestic Business Corporation In compliance with the requirements of section 204 of the Business Corporation Law, act of May 5, 1933 (P.L. 364) (15 P.S. S1204) the undersigned, desiring to be incorporated as a business corporation, hereby certifies that: 1. The name of the corporation is ATLAS RESOURCES, INC. 2. The location and post office address of the initial registered office of the corporation in this Commonwealth is: 311 Rouser Road, Coraopolis, Pennsylvania 15108. 3. The corporation is incorporated under the Business Corporation Law of the Commonwealth of Pennsylvania for the following purpose or purposes: To engage in and do any lawful act concerning any or all lawful business for which corporations may be incorporated under this act. 4. The term for which the corporation is to exist is perpetual. 5. The aggregate number of shares which the corporation shall have authority to issue is: Five Hundred (500) shares of capital stock without par value. 6. The name and post office address of each incorporator and the number and class of shares subscribed by such incorporator is:
Number and Name Address Class of Shares Ira S. Pimm, Jr. 2225 Land Title Building 1 Philadelphia, PA 19110
IN TESTIMONY WHEREOF, the incorporator has signed and sealed these Articles of Incorporation this 5th day of July, 1979. Ira S. Pimm, Jr. _______________________________(SEAL) Filed this 9th day of July, 1979. Commonwealth of Pennsylvania Department of State ETHEL D. ALLEN, D.O. Secretary of the Commonwealth COMMONWEALTH OF PENNSYLVANIA DEPARTMENT OF STATE TO ALL TO WHOM THESE PRESENTS SHALL COME, GREETING: WHEREAS, Under the provisions of the Business Corporation Law, approved the 5th day of May, Anno Domini one thousand nine hundred and thirty-three, P.L. 364, as amended, the Department of State is authorized and required to issue a CERTIFICATE OF INCORPORATION evidencing the incorporation of a business corporation organized under the terms of that law. AND WHEREAS, The stipulations and conditions of that law have been fully complied with by the persons desiring to incorporate as ATLAS RESOURCES, INC. THEREFORE, KNOW YE, That subject to the Constitution of this Commonwealth and under the authority of the Business Corporation Law, I do by these presents, which I have caused to be sealed with the Great Seal of the Commonwealth, create, erect, and incorporate the incorporators of and the subscribers to the shares of the proposed corporation named above, their associates and successors, and also those who may thereafter become subscribers or holders of the shares of such corporation, into a body politic and corporate in deed and in law by the name chosen hereinbefore specified, which shall exist perpetually and shall be invested with and have and enjoy all the powers, privileges, and franchises incident to a business corporation and be subject to all the duties, requirements and restrictions specified and enjoined in and by the Business Corporation Law and all other applicable laws of this Commonwealth. GIVEN under my hand and the Great Seal of the Commonwealth, at the City of SEAL OF THE STATE Harrisburg, this 9th day of July, OF PENNSYLVANIA in the year of our Lord one thousand nine hundred and seventy-nine and of the Commonwealth the two hundred and fourth. ETHEL D. ALLEN, D.O. Secretary of the Commonwealth EX-3 5 ex3-b.txt EXHIBIT 3(B) Exhibit 3(b) ------------ BYLAWS OF ATLAS RESOURCES, INC. Exhibit 3(b) ATLAS RESOURCES, INC. BY-LAWS ARTICLE I - OFFICES 1. Registered Office. The registered office of the Corporation shall be located within the Commonwealth of Pennsylvania, at such place as the Board of Directors shall, from time to time, determine. 2. Other Offices. The Corporation may also have offices at such other places as the Board of Directors may from time to time, determine. ARTICLE II - SHAREHOLDERS' MEETINGS 1. Place of Shareholders' Meetings. Meetings of Shareholders shall be held at such place within or without the Commonwealth of Pennsylvania as shall be fixed by the Board of Directors from time to time. If no such place is fixed by the Board of Directors, meetings of the Shareholders shall be held at the registered office of the Corporation. 2. Annual Meeting. A meeting of the Shareholders of the Corporation shall be held in each calendar year, commencing with the year 1980, on the________________ at ____ o'clock _M., if not a legal holiday, and if such day is a legal holiday, then such meeting shall be held on the next business day. At such annual meeting, there shall be held an election for a Board of Directors to serve for the ensuing year and until their successors shall be duly elected. Unless the Board of Directors shall deem it advisable, financial reports of the Corporation's business need not be sent to the Shareholders and need not be presented at the annual meeting. If any report is deemed advisable by the Board of Directors, such report may contain such information as the Board of Directors shall determine and need not be certified by a Certified Public Accountant unless the Board of Directors shall so direct. 3. Special Meetings. Special meetings of the Shareholders may be called at any time. (a) By the President of the Corporation; or (b) By a majority of the Board of Directors; or (c) By the holders of not less than one-fifth of all the shares outstanding and entitled to vote. Upon the written request of any person entitled to call a special meeting, which request shall set forth the purpose for which the meeting is desired, it shall be the duty of the Secretary to give notice of such meeting to be held at such time, not less than ten (10) nor more than sixty (60) days after the receipt of such request, as the Secretary may fix. If the Secretary shall neglect or refuse to give such notice within ten (10) days after receipt of such request, the person or persons making such request may do so. 4. Notices of Shareholders' Meetings. Except as otherwise specifically provided by law, at least five days' written notice shall be given of the annual meeting and any special meeting of the Shareholders. Such notices shall be given in the name of the Secretary or the Assistant Secretary. 5. Quorum. The presence, in person or by proxy, of the holders of a majority of the outstanding shares entitled to vote shall constitute a quorum. The Shareholders present at a duly organized meeting can continue to do business until adjournment, notwithstanding the withdrawal of enough Shareholders to leave less than a quorum. If a meeting cannot be organized because of the absence of a quorum, those present may, except as otherwise provided by law, adjourn the meeting to such time and place as they may determine. In the case of any meeting for the election of Directors, those Shareholders who attend the second of such adjourned meetings, although less than a quorum as fixed in this section, shall nevertheless constitute a quorum for the purpose of electing Directors. 6. Voting. The officer or agent having charge of the transfer books of the Corporation shall make, at least five days before any meeting of Shareholders, a complete list of the Shareholders entitled to vote at such meeting, arranged in alphabetical order, with the address of and the number of shares held by each, which list shall be kept on file at the registered office of the Corporation and shall be subject to inspection by any Shareholder at any time during usual business hours. Such list shall also be produced and kept open at the time and place of the meeting and shall be subject to the inspection of any Shareholder during the whole time of the meeting. At all Shareholders' meetings, Shareholders entitled to vote may attend and vote either in person or by proxy. All proxies shall be in writing and shall be filed with the Secretary of the Corporation. No unrevoked proxy shall be valid after eleven months from the date of execution, unless a longer time is expressly provided therein; but in no event shall a proxy, unless coupled with an interest, be valid after three years after the date of its execution. Except as otherwise specifically provided by law, all matters coming before the meeting shall be determined by a vote by shares. Such vote may be taken by voice unless a Shareholder demands that it be taken by ballot, in which event the vote shall be taken by written ballot, and the Judge or Judges of Election or, if none, the Secretary of the meeting, shall tabulate and certify the results of such vote. 7. Informal Action by Shareholders. Any action which may be taken at a meeting of the Shareholders may be taken without a meeting, if a consent in writing, setting forth the action so taken, shall be signed by all of the Shareholders who would be entitled to vote at a meeting for such purpose and shall be filed with the Secretary of the Corporation. ARTICLE III - BOARD OF DIRECTORS 1. Number. The business and affairs of the Corporation shall be managed by a Board of two Directors. 2. Place of Meeting. Meetings of the Board of Directors may be held at such place within the Commonwealth of Pennsylvania, or elsewhere, as a majority of the Directors may from time to time appoint, or as may be designated in the notice calling the meeting. 3. Regular Meetings. A regular meeting of the Board of Directors shall be held annually, immediately following the annual meeting of Shareholders at the place where such meeting of the Shareholders is held or at such other place, date and hour as a majority of the newly elected Directors may designate. At such meeting the Board of Directors shall elect officers of the Corporation. In addition to such regular meeting, the Board of Directors shall have the power to fix by resolution the place, date and hour of other regular meetings of the Board. 4. Special Meetings. Special meetings of the Board of Directors shall be held whenever ordered by the President or by a majority of the Directors in office. 5. Notices of Meetings of Board of Directors. (a) Regular Meetings. No notice shall be required to be given of any regular meeting, unless the same be held at other than the time or place for holding such meetings as fixed in accordance with Article III, Paragraph 3 of these By-Laws, in which event one day's notice shall be given of the time and place of such meeting. (b) Special Meetings. At least one day's notice shall be given or the time when, place where, and purpose for which any special meeting of the Board of Directors is to be held. 6. Quorum. A majority of the Directors in office shall be necessary to constitute a quorum for the transaction of business, and the acts of a majority of the Directors present at a meeting at which a quorum is present shall be the acts of the Board of Directors. If there be less than a quorum present, the majority of these present may adjourn the meeting from time to time and place to place and shall cause notice of each such adjourned meeting to be given to all absent Directors. 7. Informal Action by the Board of Directors. If all the Directors shall severally or collectively consent in writing to any action to be taken by the Corporation, such action shall be as valid corporate action as though it had been authorized at a meeting of the Board of Directors. 8. Powers. (a) General Powers. The Board of Directors shall have all the power and authority granted by law to the Board, including all powers necessary or appropriate to the management of the business and affairs of the Corporation. (b) Specific Powers. Without limiting the general powers conferred by the last preceding clause and the powers conferred by the Articles and By-Laws of the Corporation, it is hereby expressly declared that the Board of Directors shall have the following powers: (1) To confer upon any officer or officers of the Corporation, the power to choose, remove or suspend assistant officers, agents or servants. (2) To appoint any person, firm or corporation to accept and hold in trust for the Corporation any property belonging to the Corporation, or in which it is interested, and to authorize any such person, firm or corporation to execute any documents and perform any duties that may be requisite in relation to any such trust. (3) To appoint a person or persons to vote shares of another corporation held and owned by the Corporation. (4) By resolution adopted by a majority of the whole Board of Directors, to delegate two or more of its number to constitute an executive committee which, to the extent provided in such resolution, shall have and exercise the authority of the Board of Directors in the management of the business of the Corporation. (5) To fix the place, time and purpose of meetings of Shareholders. (6) To determine who shall be authorized on the Corporation's behalf to sign bills, notes, receipts, acceptances, endorsements, checks, releases, contracts and documents. 9. Compensation of Directors. Compensation of Directors, if any, shall be as determined from time to time by resolution of the Board of Directors. 10. Removal of Directors by Shareholders. The entire Board of Directors or any individual Director may be removed from office without assigning any cause by a majority vote of the holders of the outstanding shares entitled to vote at an election of Directors. In case the Board of Directors or any one or more Directors be so removed, new Directors may be elected at the same time. Unless the entire Board of Directors be removed, no individual Director shall be removed in case the votes of a sufficient number of shares are cast against the resolution for his removal which, if voted at an election of the full Board of Directors, would be sufficient to elect one or more Directors. 11. Vacancies. Vacancies in the Board of Directors, including vacancies resulting from an increase in the number of Directors, shall be filled by a majority of the remaining members of the Board of Directors though less than a quorum, and each person so elected shall be a Director until his successor is elected by the Shareholders, who may make such election at the next annual meeting of the Shareholders or at any special meeting duly called for that purpose and held prior thereto. ARTICLE IV - OFFICERS 1. Election and Office. The Corporation shall have a President, a Secretary and a Treasurer, who shall be elected by the Board of Directors. The Board of Directors may elect as additional officers, a Chairman of the Board of Directors, one or more Vice-Presidents, and one or more assistant officers. Any two or more offices may be held by the same person. 2. Term. The President, the Secretary and the Treasurer shall each serve for a term of one year and until their respective successors are duly elected and qualified, unless removed from office by the Board of Directors during their respective tenures. The term of office of any other officer shall be as specified by the Board of Directors. 3. Powers and Duties of the President. Unless otherwise determined by the Board of Directors, the President shall have the usual duties of an executive officer with general supervision over and direction of the affairs of the Corporation. In the exercise of these duties and subject to the limitations of the laws of the Commonwealth of Pennsylvania, these By-Laws, and the actions of the Board of Directors, he may appoint, suspend and discharge employees and agents, shall preside at all meetings of the Shareholders at which he shall be present, and unless there is a Chairman of the Board of Directors, shall preside at all meetings of the Board of Directors and shall be a member of all committees. He shall also do and perform such other duties as from time to time may be assigned to him by the Board of Directors. Unless otherwise determined by the Board of Directors, the President shall have full power and authority on behalf of the Corporation, to attend and to act and to vote at any meeting of the Shareholders of any corporation in which the Corporation may hold stock, and, at any such meeting, shall possess and may exercise any and all the rights and powers incident to the ownership of such stock and which, as the owner thereof, the Corporation might have possessed and exercised. 4. Powers and Duties of the Secretary. Unless otherwise determined by the Board of Directors, the Secretary shall keep the minutes of all meetings of the Board of Directors, Shareholders and all committees, in books provided for that purpose, and shall attend to the giving and serving of all notices for the Corporation. He shall have charge of the corporate seal, the stock certificate books, transfer books and stock ledgers, and such other books and papers as the Board of Directors may direct. He shall perform all other duties ordinarily incident to the office of Secretary and shall have such other powers and perform such other duties as may be assigned to him by the Board of Directors. 5. Powers and Duties of the Treasurer. Unless otherwise determined by the Board of Directors, the Treasurer shall have charge of all the funds and securities of the Corporation which may come into his hands. When necessary or proper, unless otherwise ordered by the Board of Directors, he shall endorse for collection on behalf of the Corporation, checks, notes and other obligations, and shall deposit the same to the credit of the Corporation in such banks or depositories as the Board of Directors may designate and shall sign all receipts and vouchers for payments made to the Corporation. He shall enter regularly, in books of the Corporation to be kept by him for the purpose, full and accurate account of all moneys received and paid by him on account of the Corporation. Whenever required by the Board of Directors, he shall render a statement of the financial condition of the Corporation. He shall at all reasonable times exhibit his books and accounts to any Director of the Corporation, upon application at the office of the Corporation during business hours. He shall have such other powers and shall perform such other duties as may be assigned to him from time to time by the Board of Directors. He shall give such bond, if any, for the faithful performance of his duties as shall be required by the Board of Directors and any such bond shall remain in the custody of the President. 6. Powers and Duties of the Chairman of the Board of Directors. Unless otherwise determined by the Board of Directors, the Chairman of the Board of Directors, if any, shall preside at all meetings of Directors and shall serve ex officio as a member of every committee of the Board of Directors. He shall have such other powers and perform such further duties as may be assigned to him by the Board of Directors. 7. Powers and Duties of Vice-Presidents and Assistant Officers. Unless otherwise determined by the Board of Directors, each Vice-President and each assistant officer shall have the powers and perform the duties of his respective superior officer. Vice-Presidents and Assistant officers shall have such rank as shall be designated by the Board of Directors and each, in the order of rank, shall act for such superior officer in his absence or upon his disability or when so directed by such superior officer or by the Board of Directors. The President shall be the superior officer of the Vice-Presidents. The Treasurer and Secretary shall be the superior officers of the Assistant Treasurers and Assistant Secretaries, respectively. 8. Delegation of Office. The Board of Directors may delegate the powers or duties of any officer of the Corporation to any other officer or to any Director from time to time. 9. Vacancies. The Board of Directors shall have the power to fill any vacancies in any office occurring from whatever reason. ARTICLE V - CAPITAL STOCK 1. Share Certificates. Every share certificate shall be signed by the President or a Vice-President and by the Treasurer, Assistant Treasurer, Secretary or Assistant Secretary and sealed with the corporate seal, which may be a facsimile, engraved or printed, but where such certificate is signed by a transfer agent or by a transfer clerk and a registrar, the signature of any corporate officer upon such certificate may be a facsimile, engraved or printed. 2. Transfer of Shares. Transfer of shares shall be made on the books of the Corporation only upon surrender of the share certificate, duly endorsed and otherwise in proper form for transfer, which certificate shall be cancelled at the time of transfer. 3. Determination of Shareholders of Record and Closing Transfer Books. The Board of Directors may fix a time, not more than fifty days prior to the date of any meeting of Shareholders, or the date fixed for the payment of any dividend or distribution, or the date for the allotment of rights, or the date when any change or conversion or exchange of shares will be made or go into effect, as a record date for the determination of the Shareholders entitled to notice of or to vote at any such meeting, or entitled to receive payment of any such dividend or distribution, or to receive any such allotment of rights, or to exercise the rights in respect to any such change, conversion or exchange of shares or otherwise. In such case, only such Shareholders as shall be Shareholders of record on the date so fixed shall be entitled to notice of or to vote at such meeting, or to receive payment of such dividend, or to receive such allotment of rights, or to exercise such rights, as the case may be, notwithstanding any transfer of any shares on the books of the Corporation after any record date fixed as aforesaid. The Board of Directors may close the books of the Corporation against transfers of shares during the whole or any part of such period, and in such case written or printed notice thereof shall be mailed at least ten (10) days before the closing thereof to each Shareholder of record at the address appearing on the records of the Corporation or supplied by him to the Corporation for the purpose of notice. While the stock transfer books of the Corporation are closed, no transfer of shares shall be made thereon. Unless a record date is fixed by the Board of Directors for the determination of Shareholders entitled to receive notice of or vote at, a Shareholders' Meeting, transferees of shares which are transferred on the books of the Corporation within ten (10) days next preceding the date of such meeting shall not be entitled to notice of or to vote at such meeting. The Corporation may treat the registered owner of each share of stock as the person exclusively entitled to vote, to receive notifications and otherwise, to exercise all the rights and powers of the owner thereof. 4. Lost Share Certificates. Unless waived in whole or in part by the Board of Directors from time to time, any person requesting the issuance of a new certificate in lieu of an alleged loss, destroyed, mislaid or wrongfully taken certificate, shall (1) make an affidavit or affirmation of the facts and circumstances surrounding the same; (2) advertise such facts to the extent and in such manner as the Board of Directors may require; (3) give the Corporation a bond of indemnity in form, and with one or more sureties satisfactory to the Board, in an amount to be determined by the Board, whereupon the proper officers may issue a new certificate. ARTICLE VI - NOTICES 1. Contents of Notice. Whenever any notice of a meeting is required to be given pursuant to these By-Laws or the Articles, or otherwise, the notice shall specify the place, day and hour of the meeting and, in the case of a special meeting or where otherwise required by law, the general nature of the business to be transacted at such meeting. 2. Method of Notice. All notices shall be given to each person entitled thereto, either personally or by sending a copy thereof through the mail or by telegraph, charges pre-paid, to his address appearing on the books of the Corporation, or supplied by him to the Corporation for the purpose of notice. If notice is sent by mail or telegraph, it shall be deemed to have been given to the person entitled thereto when deposited in the United States Mail or with the telegraph office for transmission. If no address for a Shareholder appears on the books of the Corporation and such Shareholder has not supplied the Corporation with an address for the purpose of notice, notice deposited in the United States Mail addressed to such Shareholder, care of General Delivery in the City in which the Registered Office of the Corporation is located, shall be sufficient. 3. Waiver of Notice. Whenever any written notice is required to be given by the Articles or these By-Laws, a waiver thereof in writing, signed by the person or persons entitled to such notice, whether before or after the time stated therein, shall be deemed equivalent to the giving of such notice. Except in the case of a special meeting, neither the business to be transacted at nor the purpose of the meeting need be specified in the waiver of notice of such meeting. ARTICLE VII - INDEMNIFICATION OF DIRECTORS, OFFICERS AND OTHER PERSONS. 1. Each Director and each officer and former Directors or officers, and any person who may have served, at its request, as a Director or officer of another corporation in which it owns shares of capital stock or of which it is a creditor, shall be indemnified by the Corporation against expenses actually and necessarily incurred by them in connection with the defense of any action, suit or proceeding in which they, or any of them, are made parties or a party by reason of being or having been directors or officers or a Director or officer of the Corporation or of such other corporation, except in relation to matters as to which any such Director or officer or former Director or officer or person shall be adjudged, in such action, suit, or proceeding, to be liable for negligence or misconduct in the performance of duty. Such indemnification shall not be deemed exclusive of any other rights to which those indemnified may be entitled under any By-Laws, Agreement, vote of Shareholders, or otherwise. ARTICLE VIII - FISCAL YEAR 1. The Board of Directors shall have the power by resolution to fix the fiscal year of the Corporation. If the Board of Directors shall fail to do so, the President shall fix the fiscal year. ARTICLE IX - AMENDMENTS 1. The Shareholders entitled to vote thereon shall have the power to alter, amend or repeal these By-Laws, by a majority of those voting, at any regular or special meeting, duly convened after notice to the Shareholders of such purpose. The Board of Directors, by a majority vote of those voting, shall have the power to alter, amend and repeal these By-Laws, at any regular or special meeting duly convened after notice of such purpose, subject always to the power of the Shareholders to change such action. EX-4 6 ex-4a.txt EXHIBIT 4(A) EXHIBIT 4(a) CERTIFICATE OF LIMITED PARTNERSHIP FOR ATLAS AMERICA PUBLIC #14-2004 L.P. DELAWARE -------- The First State I, HARRIET SMITH WINDSOR, SECRETARY OF STATE OF THE STATE OF DELAWARE, DO HEREBY CERTIFY THE ATTACHED IS A TRUE AND CORRECT COPY OF THE CERTIFICATE OF LIMITED PARTNERSHIP OF "ATLAS AMERICA PUBLIC #14-2004 L.P.", FILED IN THIS OFFICE ON THE SIXTH DAY OF MAY, A.D. 2004, AT 12 O'CLOCK P.M. 3799843 8100 [SEAL] /s/ Harriet Smith Windsor ----------------------------- 040330860 Harriet Smith Windsor, Secretary of State AUTHENTICATION: 3095280 DATE: 05-06-04 State of Delaware Secretary of State Division of Corporations Delivered 12:00 PM 05/06/2004 FILED 12:00 PM 05/06/2004 SRV 040330860 - 3799843 FILE STATE OF DELAWARE CERTIFICATE OF LIMITED PARTNERSHIP o THE UNDERSIGNED, desiring to form a limited partnership pursuant to the Delaware Revised Uniform Limited Partnership Act, 6 Delaware Code, Chapter 17, do hereby certify as follows: o FIRST: The name of the limited partnership is ATLAS AMERICA PUBLIC #14-2004 L.P. o SECOND: The address of its registered office in the State of Delaware is 110 S. POPLAR STREET, SUITE 101 in the city of WILMINGTON, DE 19801 The name of the Registered Agent at such address is ANDREW M. LUBIN o THIRD: The name and mailing address of each general partner is as follows: ATLAS RESOURCES, INC. MANAGING GENERAL PARTNER 311 ROUSER ROAD, P.O. BOX 611 MOON TOWNSHIP, PA 15108 o IN WITNESS WHEREOF, the undersigned has executed this Certificate of Limited Partnership of Atlas America Public #14-2004 L.P. as of May 3, 2004. Partnership Name BY: ATLAS RESOURCES, INC. MANAGING GENERAL PARTNER /s/ KAREN A. BLACK ------------------------------------------- KAREN A. BLACK, VICE PRESIDENT -- PARTNERSHIP ADMINISTRATION EX-5 7 ex-5.txt EXHIBIT 5 EXHIBIT 5 OPINION OF KUNZMAN & BOLLINGER, INC. AS TO THE LEGALITY OF THE UNITS KUNZMAN & BOLLINGER, INC. ATTORNEYS-AT-LAW 5100 N. BROOKLINE, SUITE 600 OKLAHOMA CITY, OKLAHOMA 73112 Telephone (405) 942-3501 Fax (405) 942-3527 Exhibit 5 June 24, 2004 Atlas Resources, Inc. 311 Rouser Road Moon Township, Pennsylvania 15108 RE: ATLAS AMERICA PUBLIC #14-2004 PROGRAM ------------------------------------- Gentlemen: You have requested our opinion on certain issues pertaining to Atlas America Public #14-2004 Program (the "Program"), which is a series of up to three limited partnerships formed or to be formed under the Limited Partnership Laws of Delaware. Atlas Resources, Inc., a Pennsylvania corporation, will be the Managing General Partner of each Partnership. Basis of Opinion - ---------------- Our opinion is based on our review of a certain Registration Statement on Form S-1 and any amendments thereto, including any post-effective amendments, for the Program (the "Registration Statement") as filed with the Securities and Exchange Commission (the "Commission"), including the Prospectus and the Form of Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #14-2004 L.P. [Form of Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Public #14-2005(___) L.P.] (the "Partnership Agreement"), the Form of Subscription Agreement and the Form of Drilling and Operating Agreement for Atlas America Public #14-2004 L.P. [Atlas America Public #14-2005(___) L.P.] contained therein, and on our review of such other documents and records as we have deemed necessary to review for purposes of rendering our opinion. As to various questions of fact material to our opinion which we have not independently verified, we have relied on certain representations made to us by officers and directors of the Managing General Partner. In rendering the opinion herein provided, we have assumed each subscriber has paid the consideration specified in the subscriber's Subscription Agreement and the due execution and delivery of all relevant documents by all parties thereto. As used in our opinion, the term "Units" includes the Limited Partner Units, the Investor General Partner Units and the limited partner units into which the Investor General Partner Units will be converted as described in the Registration Statement. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 2 Opinion - ------- Based upon the foregoing, we are of the opinion that: The Units when issued and sold in accordance with the Registration Statement, as amended at the time it becomes effective with the Commission, and the respective Partnership Agreement for the Partnership to which the respective Units relate, and upon the filing with the Delaware Secretary of State of such Partnership Agreement, a certificate thereof or an appropriate amendment or amendments to such Partnership Agreement reflecting the admission of the subscribers thereto for Investor General Partner Units as additional general partners or, thereafter, the conversion of the Investor General Partners to Limited Partners, in accordance with Delaware law, the Units when issued against payment therefor as contemplated by the Prospectus and each respective Partnership Agreement will be validly issued and fully paid and nonassessable, except that the Managing General Partner may call for additional Capital Contributions from the Investor General Partners, including Investor General Partners who have been converted to Limited Partners, in a Partnership if necessary to pay that Partnership's obligations or liabilities: o which arose before the conversion of the Investor General Partners to Limited Partners, and for which the Investor General Partners are liable because of their status as general partners of the Partnership at the time the obligations and liabilities arose; and o which exceed the Partnership's assets, insurance proceeds, and the Managing General Partner's indemnification of the Investor General Partners from any liability incurred in connection with the Partnership which is in excess of the Investor General Partners' interest in the Partnership's undistributed net assets and insurance proceeds. We hereby consent to the use of this opinion as an Exhibit to the Registration Statement and to the reference to this firm in the Prospectus included in the Registration Statement. Yours very truly, /s/ Kunzman & Bollinger, Inc. KUNZMAN & BOLLINGER, INC. EX-8 8 ex-8.txt EXHIBIT 8 EXHIBIT 8 OPINION OF KUNZMAN & BOLLINGER, INC. AS TO TAX MATTERS KUNZMAN & BOLLINGER, INC. ATTORNEYS-AT-LAW 5100 N. BROOKLINE, SUITE 600 OKLAHOMA CITY, OKLAHOMA 73112 Telephone (405) 942-3501 Fax (405) 942-3527 Exhibit 8 June 24, 2004 Atlas Resources, Inc. 311 Rouser Road Moon Township, Pennsylvania 15108 RE: Atlas America Public #14-2004 Program - Tax Opinion --------------------------------------------------- Gentlemen: LIMITATIONS ON USE OF TAX OPINION. With respect to any material federal income tax issue on which we have given an opinion in this letter, our opinion may not be sufficient for the Participants in any Partnership to use for the purpose of avoiding penalties relating to a substantial understatement of income tax under Section 6662(d) of the Internal Revenue Code. Prospective Participants are urged to seek advice from their own tax advisors regarding the material federal tax consequences to them of an investment in a Partnership in light of their individual federal income tax circumstances. INTRODUCTION. You have requested our opinions on the material federal income tax issues pertaining to Atlas America Public #14-2004 Program (the "Program"), a series of up to three natural gas and oil drilling limited partnerships (each a "Partnership" or collectively the "Partnerships"), all of which have been or will be formed under the Delaware Revised Uniform Limited Partnership Act before they begin their drilling activities. The limited partnerships are Atlas America Public #14-2004 L.P., Atlas America Public #14-2005(A) L.P., and Atlas America Public #14-2005(B) L.P. We have acted as Special Counsel to the Program with respect to the offering of Units in the Partnerships to potential Participants. Atlas Resources, Inc. ("Atlas Resources") will be the Managing General Partner of each of the Partnerships. Capitalized terms used and not otherwise defined in this letter have the respective meanings assigned to them in the form of Amended and Restated Certificate and Agreement of Limited Partnership for the Partnerships (the "Partnership Agreement"), which is included as Exhibit (A) to the Prospectus. BASIS FOR OPINIONS AND MANAGING GENERAL PARTNER'S REPRESENTATIONS. Our opinions and the "Summary Discussion of the Material Federal Income Tax Consequences of an Investment in a Partnership" section of this letter are based in part on our review of: o the Registration Statement on Form S-1 for the Partnerships as originally filed with the SEC, including the Prospectus, the Partnership Agreement and the form of Drilling and Operating Agreement included as exhibits in the Prospectus; o other corporate records, certificates, agreements, instruments and documents as we deemed relevant and necessary to review as a basis for our opinions; and o current provisions of the Code, existing, temporary and currently proposed Treasury Regulations promulgated under the Code, the legislative history of the Code, existing administrative rulings and practices of the IRS, and judicial decisions. Future changes in existing law, which may take effect retroactively, may cause the actual tax consequences of an investment in the Partnerships to vary substantially from those set forth in this letter, and could render our opinions inapplicable. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 2 In addition, many of the material federal income tax consequences of an investment in a Partnership depend in part on determinations which are inherently factual in nature. Thus, our opinions are based in part on the statements made by the Partnerships or the Managing General Partner in the Prospectus concerning the Partnerships and their proposed activities, including forward-looking statements. (See "Forward-Looking Statements and Associated Risks" in the Prospectus.) We also have obtained from you representations with respect to certain relevant facts relating to the Partnerships which we have assumed for purposes of our opinions. Based on the foregoing, we are satisfied that our opinions take into account all relevant facts, and that the material facts (including our factual assumptions and your representations) are accurately and completely described in this letter and, where appropriate, in the Prospectus. Any material inaccuracy in your representations may render our opinions inapplicable. Included among your representations are the following: o The Partnership Agreement will be duly executed by the Managing General Partner and the Participants in each Partnership and recorded in all places required under the Delaware Revised Uniform Limited Partnership Act and any other applicable limited partnership act. Also, each Partnership, when formed, will operate its business as described in the Prospectus and in accordance with the terms of the Partnership Agreement, the Delaware Revised Uniform Limited Partnership Act, and any other applicable limited partnership act. o No Partnership will elect to be taxed as a corporation. o Each Partnership ultimately will own legal title to its Working Interest in all of its Prospects, although initially title to the Prospects will be held in the name of the Managing General Partner, its Affiliates or other third-parties as nominee for the Partnership, in order to facilitate the acquisition of the Leases. o Generally, 100% of the Working Interest in each Partnership's Prospects will be assigned to that Partnership, however, the Managing General Partner anticipates that each Partnership will acquire less than 100% of the Working Interest in one or more of its Prospects. o The Drilling and Operating Agreement for each Partnership will be duly executed and will govern the drilling and, if warranted, the completion and operation of that Partnership's wells. o Based on information the Managing General Partner has concerning drilling rates of third-party drilling companies in the Appalachian Basin, the estimated costs of non-affiliated persons to drill and equip wells in the Appalachian Basin as reported for 2002 by an independent industry association which surveyed other non-affiliated operators in the area, and information it has concerning increases in drilling costs in the area since then, the amounts that will be paid by the Partnerships to the Managing General Partner or its Affiliates under the Drilling and Operating Agreement to drill and complete each Partnership's wells at Cost plus 15% are reasonable and competitive amounts that ordinarily would be paid for similar services in similar transactions between Persons having no affiliation and dealing with each other "at arms' length." o Based on the Managing General Partner's experience and its knowledge of industry practices in the Appalachian Basin, its allocation of the drilling and completion price to be paid by each Partnership to the Managing General Partner or its Affiliates as a third-party general drilling contractor to drill and complete a well between Intangible Drilling Costs and Tangible Costs as set forth in "Compensation - Drilling Contracts" in the Prospectus is reasonable. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 3 o Each Partnership will own only Working Interests in all of its Prospects, and will elect to deduct currently all Intangible Drilling Costs. o Depending primarily on when each Partnership's subscriptions are received, the Managing General Partner anticipates that Atlas America Public #14-2004 L.P. will prepay in 2004 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2005. In addition, the Managing General Partner anticipates that Atlas America Public #14-2005(B) L.P., which may close on December 31, 2005, may prepay in 2005 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2006. The Managing General Partner, however, anticipates that all of the wells in Atlas America Public #14-2005(A) L.P., which is targeted to have its final closing on May 31, 2005 (which is not binding on the Partnership) will be drilled and completed in 2005 and, therefore, that Partnership will not prepay any Intangible Drilling Costs in 2005 for drilling activities in 2006. o Each Partnership will have a calendar year taxable year and use the accrual method of accounting. o Based on the Managing General Partner's experience (see "Prior Activities" in the Prospectus) and the intended operations of each Partnership, as described in the Prospectus, the Managing General Partner has determined that the aggregate deductions, including depletion deductions, and 350% of the aggregate credits, if any, which will be claimed by the Managing General Partner and the Participants in each Partnership, will not during the first five tax years following the funding of each Partnership, exceed twice the amounts invested by the Managing General Partner and the Participants in the Partnership. Thus, the Managing General Partner will not register any of the Partnerships with the IRS as a "tax shelter." o The Investor General Partner Units in a Partnership will not be converted to Limited Partner Units before all of the wells in that Partnership have been drilled and completed. The Managing General Partner anticipates that all of the productive wells in each Partnership will be drilled, completed and placed in service no more than 12 months after the Partnership's final closing. Thus, the Managing General Partner anticipates that conversion will be in 2005 for Atlas America Public #14-2004 L.P., and in 2006 for both Atlas America Public #14-2005(A) L.P. and Atlas America Public #14-2005(B) L.P. o No Units in any of the Partnerships will be traded on an established securities market. o The principal purpose of each Partnership is to locate, produce and market natural gas and oil on a profitable basis, apart from tax benefits, as discussed in the Prospectus. (See, in particular, "Prior Activities," "Management," "Proposed Activities," and "Appendix A" in the Prospectus which, when supplemented or amended for Atlas America Public #14-2005(A) L.P. and Atlas America Public #14-2005(B) L.P., will cover a portion of the Prospects proposed to be drilled by each Partnership at the time Units in the respective Partnership are being offered to prospective Participants.) o A typical Participant in each Partnership will be a natural person who purchases Units in the offering and is a U.S. citizen. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 4 o The Managing General Partner does not anticipate that any of the Partnerships will elect to be treated as an "electing large partnership" under the Code for reporting and audit purposes. o Although each Partnership may make the ss.754 election under the Partnership Agreement and current Code provisions, which generally allows the Partnership to adjust the basis of its property (other than cash) if its Units are transferred, a Participant dies, or in-kind property distributions are made by it to its Participants, the Managing General Partner does not intend to make this election for any of the Partnerships. o In any administrative or judicial proceedings with the IRS, the Managing General Partner, as Tax Matters Partner, will provide the Participants with notices of the proceedings and other information as required by the Code and the Partnership Agreement. o Each Partnership will provide its Participants with the tax information needed to prepare their income tax returns. o Due to the restrictions on transfers of Units in the Partnership Agreement, the Managing General Partner does not anticipate that any of the Partnerships will ever be considered as terminated under ss.708(b) of the Code (relating to the transfer of 50% or more of a Partnership's capital and profits interests in a 12-month period). o The Managing General Partner and its Affiliates will not make or arrange financing for potential Participants to use to purchase Units in a Partnership. o The Managing General Partner will attempt to eliminate or reduce any gain to a Partnership from a Farmout, if any. SCOPE OF REVIEW AND DEFINITION OF "MATERIAL" TAX ISSUE. We have considered the provisions of 31 CFR, Part 10, ss.10.33 (Treasury Department Circular No. 230) on tax law opinions and we believe that this letter fully and fairly addresses all of the material federal income tax issues associated with an investment in a Partnership by a typical Participant. We consider material those issues which: o would significantly shelter from federal income taxes a Participant's income from sources other than the Partnership in which he invests by providing deductions in excess of the income from the Partnership in any year; o are expected to be of fundamental importance to a Participant; or o could have a significant impact (whether beneficial or adverse) on a Participant under any reasonably foreseeable circumstances. Also, in ascertaining that all material federal income tax issues have been considered, evaluating the merits of those issues, and evaluating whether the federal tax treatment set forth in our opinions is the proper tax treatment, we have not taken into account the possibility that a tax return will not be audited, an issue will not be raised on audit, or an issue may be settled. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 5 OPINIONS. Although our opinions express what we believe a court would probably conclude if presented with the applicable issues, our opinions are only predictions, and are not guarantees, of the outcome of the particular tax issues being addressed. There is no assurance that the IRS will not challenge our interpretations or that the challenge would not be sustained in the courts and cause adverse tax consequences to the Participants. Taxpayers bear the burden of proof to support claimed deductions, and our opinions are not binding on the IRS or the courts. Subject to the foregoing, in our opinion the following tax treatment with respect to a typical Participant is the proper tax treatment and will be upheld on the merits if challenged by the IRS and litigated: (1) PARTNERSHIP CLASSIFICATION. Each Partnership will be classified as a partnership for federal income tax purposes, and not as a corporation. The Partnerships, as such, will not pay any federal income taxes, and all items of income, gain, loss and deduction of the Partnerships will be reportable by the Partners in the Partnership in which they invest. (2) PASSIVE ACTIVITY CLASSIFICATION. o Generally, the passive activity limitations on losses under ss.469 of the Code will apply to the Limited Partners in a Partnership, but will not apply to the Investor General Partners in the Partnership before the conversion of the Investor General Partner Units to Limited Partner Units in the Partnership. o A Partnership's income and gain from its natural gas and oil properties which are allocated to its Limited Partners, other than net income allocated to converted Investor General Partners, generally will be characterized as passive activity income which may be offset by passive activity losses. o Income or gain attributable to investments of working capital of a Partnership will be characterized as portfolio income, which cannot be offset by passive activity losses. (3) NOT A PUBLICLY TRADED PARTNERSHIP. None of the Partnerships will be treated as a publicly traded partnership under the Code. (4) 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, Tangible Costs, organization and syndication fees and other items which are required to be capitalized, are currently deductible. (5) INTANGIBLE DRILLING COSTS. Although each Partnership will elect to deduct currently all Intangible Drilling Costs, each Participant may still elect to capitalize and deduct all or part of his share of his Partnership's Intangible Drilling Costs ratably over a 60 month period as discussed in "- Alternative Minimum Tax," below. Subject to the foregoing, Intangible Drilling Costs paid by a Partnership under the terms of bona fide drilling contracts for the Partnership's wells will be deductible in the taxable year in which the payments are made and the drilling services are rendered, assuming the amounts are reasonable consideration based on the Managing General Partner's representations, and subject to certain restrictions summarized below, including basis and "at risk" limitations, and the passive activity loss limitation with respect to the Limited Partners. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 6 (6) PREPAYMENTS OF INTANGIBLE DRILLING COSTS. Depending primarily on when each Partnership's subscriptions are received, the Managing General Partner anticipates that Atlas America Public #14-2004 L.P. will prepay in 2004 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2005. In addition, the Managing General Partner anticipates that Atlas America Public #14-2005(B) L.P., which may close on December 31, 2005, may prepay in 2005 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2006. Assuming that the amounts of any prepaid Intangible Drilling Costs of a Partnership are reasonable consideration based on the Managing General Partner's representations, and based in part on the factual assumptions set forth below, the prepayments of Intangible Drilling Costs will be deductible in the year in which they are made even though all Working Interest owners in the well will not be required to prepay Intangible Drilling Costs, 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 under each Partnership's Drilling and Operating Agreement: o the estimated Intangible Drilling Costs are required to be prepaid for specified wells to be drilled and, if warranted, completed; o the drilling of all of the specified wells and substitute wells, if any, is required to be, and actually is, begun before the close of the 90th day after the close of the Partnership's taxable year in which the prepayments are made, and the wells are continuously drilled until completed, if warranted, or abandoned; and o the required prepayments are not refundable to the Partnership and any excess prepayments for Intangible Drilling Costs are applied to Intangible Drilling Costs of the other specified wells or substitute wells. (7) DEPLETION ALLOWANCE. The greater of cost depletion or percentage depletion will be available to qualified Participants as a current deduction against their share of their Partnership's natural gas and oil production income, subject to certain restrictions summarized below. (8) MACRS. Each Partnership's reasonable costs for equipment placed in its respective productive wells which cannot be deducted immediately ("Tangible Costs") will be eligible for cost recovery deductions under the Modified Accelerated Cost Recovery System ("MACRS"), generally over a seven year "cost recovery period" beginning in the taxable year each well is drilled, completed and made capable of production, i.e. placed in service, subject to certain restrictions summarized below, including basis and "at risk" limitations, and the passive activity loss limitation in the case of the Limited Partners. (9) TAX BASIS OF UNITS. Each Participant's initial adjusted tax basis in his Units will be the purchase price paid for the Units. (10) AT RISK LIMITATION ON LOSSES. Each Participant's initial "at risk" amount in the Partnership in which he invests will be the purchase price paid for the Units, assuming that: o any amount borrowed by a Participant and contributed to the Partnership is not borrowed from a Person who has an interest in the Partnership, other than as a creditor, or a "related person", as that term is defined in ss.465 of the Code, to a Person, other than the Participant, having an interest in the Partnership, other than as a creditor, and the Participant is severally, primarily, and personally liable for the borrowed amount; and KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 7 o the Participant has not protected himself from loss for amounts contributed to the Partnership through nonrecourse financing, guarantees, stop loss agreements or other similar arrangements. (11) 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 natural gas and oil properties, is substantial in light of a Participant's tax attributes that are unrelated to the Partnership in which he invests, the allocations will have "substantial economic effect" and will govern the Participant's share of those items to the extent the allocations do not cause or increase a deficit balance in his Capital Account. (12) SUBSCRIPTION. No gain or loss will be recognized by the Participants on payment of their subscriptions to the Partnership in which they invest. (13) NO TAX SHELTER REGISTRATION. None of the Partnerships is required to register with the IRS as a tax shelter. This opinion is based in part on the Managing General Partner's representations that none of the Partnerships has a tax shelter ratio greater than 2 to 1 and each Partnership will be operated as described in the Prospectus. (14) PROFIT MOTIVE, IRS ANTI-ABUSE RULE AND POTENTIALLY RELEVANT JUDICIAL DOCTRINES. The Partnerships will possess the requisite profit motive underss.183 of the Code, and the IRS anti-abuse rule in Treas. Reg.ss.1.701-2 and certain potentially relevant judicial doctrines will not have a material adverse effect on the tax consequences of an investment in a Partnership by a typical Participant as described in our opinions. These opinions are based in part on the results of the previous partnerships sponsored by the Managing General Partner as set forth in "Prior Activities" in the Prospectus, and the Managing General Partner's representations. These representations include that each Partnership will be operated as described in the Prospectus (see "Management" and "Proposed Activities" in the Prospectus), and the principal purpose of each Partnership is to locate, produce and market natural gas and oil on a profitable basis, apart from tax benefits. These representations are also supported by the geological evaluations and the other information for the Partnerships' proposed drilling areas and the specific Prospects proposed to be drilled Atlas America Public #14-2004 L.P. which are included in Appendix A to the Prospectus. (15) OVERALL EVALUATION OF TAX BENEFITS. The tax benefits of each Partnership, in the aggregate, which are a significant feature of an investment in a Partnership by a typical Participant will be realized as contemplated by the Prospectus. This opinion is based on our conclusion that substantially more than half of the material federal income tax benefits of each Partnership, in terms of their financial impact on a typical Participant in the Partnership, will be realized if challenged by the IRS. The discussion in the Prospectus under the caption "MATERIAL FEDERAL INCOME TAX CONSEQUENCES," insofar as it contains statements of federal income tax law, is correct in all material respects. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 8 SUMMARY DISCUSSION OF THE MATERIAL FEDERAL INCOME TAX CONSEQUENCES OF AN INVESTMENT IN A PARTNERSHIP IN GENERAL. Our tax opinions are limited to those set forth above. The following is a summary of all of the material federal income tax consequences of the purchase, ownership and disposition of a Partnership's Units which will apply to typical Participants in the Partnership. Except as otherwise noted below, however, different tax considerations may apply to particular Participants, such as corporations, trusts, partnerships, foreign persons, and other prospective Participants which are subject to special treatment under federal income tax laws or are not treated as individuals for federal income tax purposes. Also, the proper treatment of the tax attributes of a Partnership by a typical Participant on his individual federal income tax return may vary from that by another typical Participant. This is because the practical utility of the tax aspects of any investment depends largely on each Participant's particular income tax position in the year in which items of income, gain, loss, deduction or credit are properly taken into account in computing the Participant's federal income tax liability. In addition, the IRS may challenge the deductions claimed by a Partnership or a Participant, or the taxable year in which the deductions are claimed, and no guaranty can be given that the challenge would not be upheld if litigated. Thus, each prospective Participant is urged to seek qualified, professional assistance in evaluating the potential tax consequences to him of an investment in a Partnership with specific reference to the Participant's own tax situation. PARTNERSHIP CLASSIFICATION. For federal income tax purposes a partnership is not a taxable entity. Thus, the partners, rather than the partnership, receive all items of income, gain, loss, deduction, credit and tax preference 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. Treas. Reg. ss.301.7701-2(a). A corporation includes a business entity organized under a State statute which describes the entity as a corporation, body corporate, body politic, joint-stock company or joint-stock association. Treas. Reg. ss.301.7701-2(b). Each Partnership, however, will be formed as a limited partnership under the Delaware Revised Uniform Limited Partnership Act which describes each Partnership as a "partnership." Thus, each Partnership automatically will be classified as a partnership unless it elects to be classified as a corporation. In this regard, the Managing General Partner has represented that none of the Partnerships will elect to be taxed as a corporation. LIMITATIONS ON PASSIVE ACTIVITIES. Under the passive activity rules of ss.469 of the Code, all income of a taxpayer who is subject to the rules is categorized as: o income from passive activities such as limited partners' interests in a business; o active income such as salary, bonuses, etc.; or o portfolio income. "Portfolio income" consists of: o interest, dividends and royalties unless earned in the ordinary course of a trade or business; and o gain or loss not derived in the ordinary course of a trade or business on the sale of property that generates portfolio income or is held for investment. Losses generated by passive activities can offset only passive income and cannot be applied against active income or portfolio income. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 9 The passive activity rules apply to individuals, estates, trusts, closely held C corporations which generally are corporations with five or fewer individuals who own directly or indirectly more than 50% of the stock, and personal service corporations other than corporations where the owner-employees together own less than 10% of the stock. However, a closely held C corporation, other than a personal service corporation, may use passive losses and credits to offset taxable income of the company figured without regard to passive income or loss or portfolio 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 in which they invest and generally will be subject to the passive activity limitations. Investor General Partners also do not materially participate in the Partnership in which they invest. However, because each Partnership will own only Working Interests in its wells and Investor General Partners will not have limited liability under the Delaware Revised Uniform Limited Partnership Act until they are converted to Limited Partners, their deductions generally will not be treated as passive deductions under the Code before the conversion. I.R.C. ss.469(c)(3). (See "- Conversion from Investor General Partner to Limited Partner," below.) However, if an Investor General Partner invests in a Partnership through an entity which limits his liability, for example, a limited partnership in which he is not a general partner, a limited liability company or an S corporation, then generally he will be subject to the passive activity limitations the same as a Limited Partner. Contractual limitations on the liability of Investor General Partners under the Partnership Agreement, however, such as insurance, limited indemnification by the Managing General Partner, etc. will not cause Investor General Partners to be subject to the passive activity limitations. A Limited Partner's "at risk" amount is reduced by losses allowed under ss.465 of the Code even if the losses are suspended by the passive activity loss limitation. (See "- `At Risk' Limitation For Losses," below.) Similarly, a Limited Partner's basis is reduced by deductions even if the deductions are suspended under the passive activity loss limitation. (See "- Tax Basis of Units," below.) Suspended losses may be carried forward indefinitely, but not back, and used to offset future years' passive activity income. A suspended loss is allowed in full when the entire interest in a passive activity is sold to an unrelated third-party in a taxable transaction and in part on the disposition of substantially all of the interest in a passive activity if the suspended loss as well as current gross income and deductions can be allocated to the part disposed of with reasonable certainty. In an installment sale, passive losses become available in the same ratio that gain recognized each year bears to the total gain on the sale. Any suspended losses remaining at a taxpayer's death are allowed as deductions on the decedent's final return, subject to a reduction to the extent the basis of the property in the hands of the transferee exceeds the property's adjusted basis immediately before the decedent's death. If a taxpayer makes a gift of his entire interest in a passive activity, the basis in the property of the person receiving the gift is increased by any suspended losses and no deductions are allowed. If the interest is later sold at a loss, the basis in the property of the person receiving the gift is limited to the fair market value on the date the gift was made. 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 passive income from a publicly traded partnership. I.R.C. ss.ss.469(k)(2) and 7704. A publicly traded partnership is a partnership whose interests are traded on an established securities market or that are readily tradable on either a secondary market or the substantial equivalent of a secondary market. However, in our opinion none of the Partnerships will be treated as a publicly traded partnership under the Code. This opinion is based primarily on the substantial restrictions in the Partnership Agreement on each Participant's ability to transfer his Units in the Partnership in which he invests. See "Transferability of Units - Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement" in the Prospectus.) Also, the Managing General Partner has represented that no Partnership's Units will be traded on an established securities market. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 10 CONVERSION FROM INVESTOR GENERAL PARTNER TO LIMITED PARTNER. If a Participant invests in a Partnership as an Investor General Partner, then his share of the Partnership's deduction for Intangible Drilling Costs in the year in which he invests will not be subject to the passive activity loss limitation because the Investor General Partner Units will not be converted by the Managing General Partner to Limited Partner Units until after all of the Partnership's wells have been drilled and completed. In this regard, the Managing General Partner has represented that it anticipates that all of the productive wells in each Partnership will be drilled, completed and placed in service no more than 12 months after the Partnership's final closing. Thus, the Managing General Partner anticipates that conversion will be in 2005 for Atlas America Public #14-2004 L.P., and in 2006 for both Atlas America Public #14-2005(A) L.P. and Atlas America Public #14-2005(B) L.P. (See "Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners" in the Prospectus and "- Drilling Contracts," below.) After the Investor General Partner Units have been converted to Limited Partner Units, each former Investor General Partner will have limited liability as a limited partner under the Delaware Revised Uniform Limited Partnership Act with respect to his interest in his Partnership's activities after the date of the conversion. Concurrently, the former Investor General Partner will become subject to the passive activity rules as a limited partner. However, the former Investor General Partner previously will have received a non-passive loss as an Investor General Partner in the year in which he invested in a Partnership as a result of the Partnership's deduction for Intangible Drilling Costs. Therefore, the Code requires that his net income from the Partnership's wells after his conversion to a limited partner must continue to be characterized as non-passive income which cannot be offset with passive losses. I.R.C. ss.469(c)(3)(B). The conversion of the Investor General Partner Units into Limited Partner Units should not have any other adverse tax consequences on an Investor General Partner unless his share of any Partnership liabilities is reduced as a result of the conversion. Rev. Rul. 84-52, 1984-1 C.B. 157. A reduction in a partner's share of liabilities is treated as a constructive distribution of cash to the partner, which reduces the basis of the partner's interest in the partnership and is taxable to the extent it exceeds his basis. (See "- Tax Basis of Units," below.) TAXABLE YEAR. Each Partnership intends to adopt a calendar year taxable year. I.R.C. ss.ss.706(a) and (b). The taxable year of a Partnership is important to a Participant because the Partnership's deductions, income and other items of tax significance must be taken into account in computing the Participant's taxable income for his taxable year within or with which the Partnership's taxable year ends. The tax year of a partnership generally must be the tax year of one or more of its partners who have an aggregate interest in partnership profits and capital of greater than 50%. METHOD OF ACCOUNTING. Each Partnership will use the accrual method of accounting for federal income tax purposes. I.R.C. ss.448(a). Under the accrual method of accounting, income is taken into account for the year in which all events have occurred which fix the right to receive it and the amount is determinable with reasonable accuracy, rather than the time of receipt. Consequently, Participants in a Partnership may have income tax liability resulting from the Partnership's accrual of income in one tax year that it does not receive until the next tax year. Expenses are deducted for the year in which all events have occurred that determine the fact of the liability, the amount is determinable with reasonable accuracy and the economic performance test is satisfied. Under ss.461(h) of the Code, if the liability of the taxpayer arises out of the providing of services or property to the taxpayer by another person, economic performance occurs as the services or property, respectively, are provided. If the liability of the taxpayer arises out of the use of the property by the taxpayer, economic performance occurs as the property is used. o A special rule in the Code, however, provides that there is economic performance in the current taxable year with respect to amounts paid by a Partnership in that taxable year for Intangible Drilling Costs of drilling and completing a natural gas or oil well so long as the drilling of the well begins before the close of the 90th day after the close of the Partnership's taxable year. I.R.C. ss.461(i). (See "- Drilling Contracts," below, for a discussion of prepaid Intangible Drilling Costs by Atlas America Public #14-2004 L.P. and Atlas America Public #14-2005(B) L.P.) KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 11 2004 AND 2005 EXPENDITURES. The Managing General Partner anticipates that all of the subscription proceeds of each Partnership will be expended in the year in which its Participants invest in that Partnership, and the related income and deductions, including the deduction for Intangible Drilling Costs, will be reflected on its Participants' federal income tax returns for that period. (See "Capitalization and Source of Funds and Use of Proceeds" and "Participation in Costs and Revenues" in the Prospectus.) Depending primarily on when each Partnership's subscription proceeds are received, the Managing General Partner anticipates that Atlas America Public #14-2004 L.P. will prepay in 2004 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2005. In addition, the Managing General Partner anticipates that Atlas America Public #14-2005(B) L.P., which may close on December 31, 2005, may prepay in 2005 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2006. The deductibility of these advance payments in the year in which a Participant invests in the Partnership cannot be guaranteed. (See "- Drilling Contracts," below.) Finally, the Managing General Partner anticipates that all of the wells in Atlas America Public #14-2005(A) L.P., which is targeted to have its final closing on May 31, 2005 (which is not binding on the Partnership), will be drilled and completed in 2005, and, therefore, it will not prepay any Intangible Drilling Costs in 2005 for drilling activities in 2006. AVAILABILITY OF CERTAIN DEDUCTIONS. Ordinary and necessary business expenses, including reasonable compensation for personal services actually rendered, are deductible in the year incurred. Treasury Regulation ss.1.162-7(b)(3) provides that reasonable compensation is only the amount as would ordinarily be paid for like services by like enterprises under like circumstances. The Managing General Partner has represented that the amounts payable by each Partnership to the Managing General Partner and its Affiliates, including the amounts payable to the Managing General Partner or its Affiliates as general drilling contractor, are reasonable amounts which would ordinarily be paid for similar services in similar transactions. (See "Compensation" in the Prospectus and "- Drilling Contracts," below.) The fees paid to the Managing General Partner and its Affiliates by the Partnerships will not be currently deductible, however, to the extent it is determined by the IRS or the courts that they are: o in excess of reasonable compensation; o properly characterized as organization or syndication fees or other capital costs such as the acquisition cost of the Leases; or o not "ordinary and necessary" business expenses. (See "- Partnership Organization and Offering Costs," below.) In the event of an audit, payments to the Managing General Partner and its Affiliates by a 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 limitations on deductions and losses summarized elsewhere in this letter, including the basis and "at risk" limitations, and the passive activity loss limitation in the case of Limited Partners, each Participant will be entitled to deduct his share of his Partnership's 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. I.R.C. ss.263(c), Treas. Reg. ss.1.612-4(a). If a Partnership re-enters an existing well as described in "Proposed Activities - Primary Areas of Operations - Mississippian/Upper Devonian Sandstone Reservoirs, Fayette County, Pennsylvania" in the Prospectus, the costs of deepening the well and completing it to deeper reservoirs, if any, (other than Tangible Costs) generally will be treated as Intangible Drilling Costs. Drilling and completion costs of a re-entry well which are not related to deepening the well, if any, however, other than Tangible Costs, generally will be treated as operating expenses which should be expensed in the taxable year KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 12 they are incurred for federal income tax purposes. Those costs (other than Tangible Costs) of the re-entry well, however, will not be characterized as Operating Costs, instead of Intangible Drilling Costs, for purposes of allocating the payment of the costs between the Managing General Partner and the Participants under the Partnership Agreement. (See "Participation in Costs and Revenues" in the Prospectus, "- Limitations on Passive Activities," above and "- Tax Basis of Units" and "- `At Risk' Limitation For Losses," below.) These deductions are subject to recapture as ordinary income rather than capital gain on the sale or other taxable disposition of the property or a Participant's Units. (See "- Sale of the Properties" and "- Disposition of Units," below.) Also, productive-well Intangible Drilling Costs may subject a Participant to an alternative minimum tax in excess of regular tax unless the Participant elects to deduct all or part of these costs ratably over a 60 month period. (See "- Alternative Minimum Tax," below.) Under the Partnership Agreement, not less than 90% of the subscription proceeds received by each Partnership from its Participants will be used to pay 100% of the Partnership's Intangible Drilling Costs of drilling and completing its wells. (See "Application of Proceeds" and "Participation in Costs and Revenues" in the Prospectus.) The IRS could challenge the characterization of a portion of these costs as currently deductible Intangible Drilling Costs and recharacterize the costs as some other item which may not be currently deductible. However, this would have no effect on the allocation and payment of the Intangible Drilling Costs by the Participants under the Partnership Agreement. In the case of corporations, other than S corporations, which are "integrated oil companies," the amount allowable as a deduction for Intangible Drilling Costs in any taxable year is reduced by 30%. I.R.C. ss.291(b)(1). Integrated oil companies are: o those taxpayers who directly or through a related person engage in the retail sale of natural gas and oil and whose gross receipts for the taxable year from such activities exceed $5,000,000; or o those taxpayers and related persons who have refinery production in excess of 50,000 barrels on any day during the taxable year. I.R.C.ss.291(b)(4). Amounts disallowed as a current deduction are allowable as a deduction ratably over the 60-month period beginning with the month in which the costs are paid or incurred. The Partnerships will not be integrated oil companies. Each Participant is urged to consult with his own personal tax advisor concerning the tax benefits to him of the deduction for Intangible Drilling Costs in the Partnership in which he invests in light of the Participant's own tax situation. DRILLING CONTRACTS. Each Partnership will enter into the Drilling and Operating Agreement with the Managing General Partner or its Affiliates, acting as a third-party general drilling contractor, to drill and complete the Partnership's 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 each Partnership, assuming a 100% Working Interest in each well, it will have reimbursement of general and administrative overhead of approximately $12,722 per net well and a profit of 15% (approximately $22,558) per net well, with respect to the Intangible Drilling Costs and the portion of Tangible Costs paid by the Participants as described in "Compensation - Drilling Contracts" in the Prospectus. 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 profit per net well also could be more or less than the dollar amount estimated by the Managing General Partner. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 13 The Managing General Partner believes the prices under the Drilling and Operating Agreement are competitive 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 being unreasonable and disallowed as a deductible Intangible Drilling Cost. (See "- Intangible Drilling Costs," above, and "Compensation" and "Proposed Activities" in the Prospectus.) The Managing General Partner anticipates that Atlas America Public #14-2005(A) L.P., which has a targeted final closing date of May 31, 2005 (which is not binding on the Partnership), will drill and complete all of its wells in 2005 and, therefore, will not prepay in 2005 any of its Intangible Drilling Costs for drilling activities that will begin in 2006. However, depending primarily on when each Partnership's subscription proceeds are received, the Managing General Partner further anticipates that Atlas America Public #14-2004 L.P. will prepay in 2004 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2005, and Atlas America Public #14-2005(B) L.P., which may close on December 31, 2005, may prepay in 2005 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2006. In Keller v. Commissioner, 79 T.C. 7 (1982), aff'd 725 F.2d 1173 (8th Cir. 1984), the Tax Court applied a two-part test for the current deductibility of prepaid intangible drilling and development costs. The test is: o the expenditure must be a payment rather than a refundable deposit; and o the deduction must not result in a material distortion of income taking into substantial consideration the business purpose aspects of the transaction. The drilling partnership in Keller entered into footage and daywork drilling contracts which permitted it to terminate the contracts at any time without default by the driller, and receive a return of the prepaid amounts less amounts earned by the driller. The Tax Court found that the right to receive, by unilateral action, a refund of the prepayments on the footage and daywork drilling contracts rendered the prepayments deposits instead of payments. Therefore, the prepayments were held to be nondeductible in the year they were paid to the extent they had not been earned by the driller. The Tax Court further found that the drilling partnership failed to show a convincing business purpose for prepayments under the footage and daywork drilling contracts. The drilling partnership in Keller also entered into turnkey drilling contracts which permitted it to stop work under the contract at any time and apply the unearned balance of the prepaid amounts to another well to be drilled on a turnkey basis. The Tax Court found that these prepayments constituted "payments" and not nondeductible deposits, despite the right of substitution. Further, the Tax Court noted that the turnkey drilling contracts obligated "the driller to drill to the contract depth for a stated price regardless of the time, materials or expenses required to drill the well," thereby locking in prices and shifting the risks of drilling from the drilling partnership to the driller. Since the drilling partnership, a cash basis taxpayer, received the benefit of the turnkey obligation in the year of prepayment, the Tax Court found that the amounts prepaid on turnkey drilling contracts clearly reflected income and were deductible in the year of prepayment. In Leonard T. Ruth, TC Memo 1983-586, a drilling program entered into nine separate turnkey contracts with a general contractor, the parent corporation of the drilling program's corporate general partner, to drill nine program wells. Each contract identified the prospect to be drilled, stated the turnkey price, and required the full price to be paid in 1974. The program paid the full turnkey price to the general contractor on December 31, 1974; the receipt of which was found by the court to be significant in the general contractor's financial planning. The program had no right to receive a refund of any of the payments. The actual drilling of the nine wells was subcontracted by the general contractor to independent contractors who were paid by the general contractor in accordance with their individual contracts. The drilling of all wells commenced in 1975 and all wells were completed that year. The amount paid by the general contractor to the independent driller for its work on the nine wells was KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 14 approximately $365,000 less than the amount prepaid by the program to the general contractor. The program claimed a deduction for intangible drilling and development costs in 1974. The IRS challenged the timing of the deduction, contending that there was no business purpose for the payments in 1974, that the turnkey arrangements were merely "contracts of convenience" designed to create a tax deduction in 1974, and that the turnkey contracts constituted assets having a life beyond the taxable year and that to allow a deduction for their entire costs in 1974 distorted income. The Tax Court, relying on Keller, held that the program could deduct the full amount of the payments in 1974. The court found that the program entered into turnkey contracts, paid a premium to secure the turnkey obligations, and thereby locked in the drilling price and shifted the risks of drilling to the general contractor. Further, the court found that by signing and paying the turnkey obligation, the program got its bargained-for benefit in 1974, therefore the deduction of the payments in 1974 clearly reflected income. Each Partnership will attempt to comply with the guidelines set forth in Keller with respect to any prepaid Intangible Drilling Costs. In the year in which a Participant invests in a Partnership, the Drilling and Operating Agreement will require the Partnership to prepay all of the Partnership's share of the estimated Intangible Drilling Costs, and all of the Participants' share of the Partnership's share of the estimated Tangible Costs, for drilling and completing specified wells, the drilling of which may begin in the following year. These prepayments of Intangible Drilling Costs should not result in a loss of a current deduction for the Intangible Drilling Costs if: o there is a legitimate business purpose for the required prepayment; o the contract is not merely a sham to control the timing of the deduction; and o there is an enforceable contract of economic substance. The Drilling and Operating Agreement will require each Partnership to prepay the Managing General Partner's estimate of the Intangible Drilling Costs and the Participants' share of the Tangible Costs to drill and complete the wells specified in the Drilling and Operating Agreement in order to enable the Operator to: o begin site preparation for the wells; o obtain suitable subcontractors at the then current prices; and o insure the availability of equipment and materials. Under the Drilling and Operating Agreement excess prepaid Intangible Drilling Costs, if any, will not be refundable to a Partnership, but instead will be applied only to Intangible Drilling Cost overruns, if any, on the other specified wells being drilled or completed by the Partnership or to Intangible Drilling Costs to be incurred by the Partnership in drilling and completing substitute wells. Under Keller, a provision for substitute wells should not result in the prepayments being characterized as refundable deposits. The likelihood that prepayments of Intangible Drilling Costs will be challenged by the IRS on the grounds that there is no business purpose for the prepayments is increased if prepayments are not required with respect to 100% of the Working Interest in the well. The Managing General Partner anticipates that less than 100% of the Working Interest will be acquired by each Partnership in one or more of its wells, and prepayments of Intangible Drilling Costs will not be required of the other owners of Working Interests in those wells. In our view, however, a legitimate business purpose for the required prepayments of Intangible Drilling Costs by the Partnerships may exist under the guidelines set forth in Keller, even though prepayments are not required by the drilling contractor with respect to a portion of the Working Interest in the wells. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 15 In addition, a current deduction for prepaid Intangible Drilling Costs is available only if the drilling of the wells begins before the close of the 90th day after the close of the taxable year in which the prepayment was made. I.R.C. ss.461(i). (See "- Method of Accounting," above.) Under the Drilling and Operating Agreement, the Managing General Partner as operator and general drilling contractor must begin drilling each of the prepaid wells before the close of the 90th day after the close of the Partnership's taxable year in which the prepayment was made, which is March 31, 2005 for Atlas America Public #14-2004 L.P. and March 31, 2006 for Atlas America Public #14-2005(B) L.P. However, the drilling of any Partnership Well may be delayed due to circumstances beyond the control of the Managing General Partner or the drilling subcontractors. These circumstances include, for example: o the unavailability of drilling rigs; o decisions of third-party operators to delay drilling the wells; o poor weather conditions; o inability to obtain drilling permits or access right to the drilling site; or o title problems; and the Managing General Partner will have no liability to any Partnership or its Participants if these types of events delay beginning the drilling of the prepaid wells past the close of the 90th day after the close of the Partnership's taxable year. If the drilling of a prepaid Partnership Well does not begin before the close of the 90th day after the close of the Partnership's taxable year in which the prepayment was made, deductions claimed by a Participant for prepaid Intangible Drilling Costs for the well in the year in which the Participant invests in the Partnership would be disallowed and deferred to the next taxable year when the well is actually drilled. No assurance can be given that on audit the IRS would not disallow the current deductibility of a portion or all of any prepaid Intangible Drilling Costs under a Partnership's drilling contracts, thereby decreasing the amount of the Participants' deductions in the Partnership for the year in which they invest in the Partnership, or that the challenge would not ultimately be sustained. In the event of disallowance, the deduction for prepaid Intangible Drilling Costs would be available in the next year when the wells are actually drilled. DEPLETION ALLOWANCE. Proceeds from the sale of each Partnership's natural gas and oil production will constitute ordinary income. A certain portion of that income will not be taxable under the depletion allowance which permits the deduction from gross income for federal income tax purposes of either the percentage depletion allowance or the cost depletion allowance, whichever is greater. I.R.C. ss.ss.611, 613 and 613A. These deductions are subject to recapture as ordinary income rather than capital gain on the sale or other taxable disposition of the property or a Participant's Units. (See " - Sale of the Properties" and " - Disposition of Units," below.) Cost depletion for any year is determined by dividing the adjusted tax basis for the property by the total units of natural gas or oil expected to be recoverable from the property and then multiplying the resultant quotient by the number of units actually sold during the year. Cost depletion cannot exceed the adjusted tax basis of the property to which it relates. Percentage depletion generally is available to taxpayers other than "integrated oil companies" as that term is defined in "- Intangible Drilling Costs," above, which does not include the Partnerships. Percentage depletion is based on a Participant's share of his Partnership's gross production income from its natural gas and oil properties. Generally, percentage depletion is available with respect to 6 million cubic feet of average daily production of natural gas or 1,000 barrels of average daily production of domestic crude oil. Taxpayers who have both natural gas and oil production may allocate the production limitation between the production. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 16 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. I.R.C. ss.613A(c)(6). The term "marginal production" includes natural gas and oil 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 equivalent to 90 mcf of natural gas, per producing well on the property in the calendar year. Most, if not all, of each Partnership's wells will be marginal producing wells under this definition in the Code and will qualify for these potentially higher rates of percentage depletion. The rate of percentage depletion for marginal production in 2004 is 15%. This rate may fluctuate 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%. Also, percentage depletion: (i) may not exceed 100% of the net income from each natural gas and oil property before the deduction for depletion; and (ii) is limited to 65% of the taxpayer's taxable income for a year computed without regard to percentage depletion, net operating loss carry-backs and capital loss carry-backs. Availability of percentage depletion must be computed separately by each Participant and not by a Partnership or for Participants in a Partnership as a whole. Potential Participants are urged to consult their own tax advisors with respect to the availability of percentage depletion to them. DEPRECIATION - MODIFIED ACCELERATED COST RECOVERY SYSTEM ("MACRS"). Tangible Costs and the related depreciation deductions of each Partnership generally are charged and allocated under the Partnership Agreement 66% to the Managing General Partner and 34% to the Participants in the Partnership. However, if the total Tangible Costs for all of the Partnership's wells that would be charged to the Participants exceeds an amount equal to 10% of the Partnership's subscription proceeds, then the excess, together with the related depreciation deductions, will be charged and allocated to the Managing General Partner. Most of each Partnership's equipment costs will be recovered through depreciation deductions over a seven year cost recovery period using the 200% declining balance method, with a switch to straight-line to maximize the deduction, beginning in the taxable year the equipment is "placed in service" by the Partnership as discussed below. I.R.C. ss.168(c). In the case of a short tax year the MACRS deduction is prorated on a 12-month basis. No distinction is made between new and used property and salvage value is disregarded. All property assigned to the 7-year class generally is treated as placed in service, or disposed of, in the middle of the year. All of these cost recovery deductions claimed by the Partnerships and their respective Participants are subject to recapture as ordinary income rather than capital gain on the sale or other taxable disposition of the property or a Participant's Units. (See "- Sale of the Properties" and "- Disposition of Units," below.) Except as discussed below, depreciation for alternative minimum tax purposes is computed using the 150% declining balance method, switching to straight-line, for most personal property. Notwithstanding the foregoing, under the Jobs and Growth Tax Relief Reconciliation Act of 2003 ("2003 Tax Act"), for federal income tax purposes Atlas America Public #14-2004 L.P., but not Atlas America Public #14-2005(A) L.P. or Atlas America Public #14-2005(B) L.P., will be entitled to an additional first-year depreciation allowance based on 50% of the adjusted basis of its "qualified" Tangible Costs, if any. For this purpose, the Partnership's "qualified" Tangible Costs means its equipment costs for productive wells which are completed and made capable of production, i.e. placed in service, before January 1, 2005. I.R.C. ss.168(k)(2) and (4). Thus, this additional first-year depreciation allowance will not be available for wells which are placed in service in 2005, even though the Participants' share of the Partnership's Tangible Costs for the equipment in the wells is prepaid in 2004, because the special rule allowing a current deduction for prepaid Intangible Drilling Costs does not apply to prepaid equipment costs. (See "- Method of Accounting" and "- Drilling Contracts," above.) In addition, the basis of the partnership's "qualified" equipment will be reduced by the additional 50% first-year depreciation allowance for purposes of calculating the regular MACRS depreciation allowances beginning in 2004. Also, if a Participant invests in Atlas America Public #14-2004 L.P., the Participant will not incur any alternative minimum tax adjustment with respect to his share of the Partnership's additional 50% first-year depreciation allowance, nor any of its other depreciation deductions for the Tangible Costs of qualified equipment it places in any productive wells that are drilled, completed and placed in service in 2004. I.R.C. ss.168(k)(2)(F). KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 17 LEASE ACQUISITION COSTS AND ABANDONMENT. Lease acquisition costs, together with the related cost depletion deduction and any abandonment loss for Lease costs, are allocated under the Partnership Agreement 100% to the Managing General Partner, which will contribute the Leases to each Partnership as a part of its Capital Contribution. TAX BASIS OF UNITS. A Participant's share of his Partnership's losses is allowable only to the extent of the adjusted basis of his Units at the end of the Partnership's taxable year. I.R.C. ss.704(d). The adjusted basis of the Participant's Units will be adjusted, but not below zero, for any gain or loss to the Participant from a sale or other taxable disposition by the Partnership of a natural gas and oil property, and will be increased by his: (i) cash subscription payment; (ii) share of Partnership income; and (iii) share, if any, of Partnership debt. The adjusted basis of a Participant's Units will be reduced by his: (i) share of Partnership losses; (ii) share of Partnership expenditures that are not deductible in computing its taxable income and are not properly chargeable to capital account; (iii) depletion deductions, but not below zero; and (iv) cash distributions from the Partnership. I.R.C. ss.ss.705, 722 and 742. The reduction in a Participant's share of Partnership liabilities, if any, is considered a cash distribution to the Participant. Although Participants will not be personally liable on any Partnership loans, Investor General Partners will be liable for other obligations of the Partnership. (See "Risk Factors - Risks Related to an Investment In a Partnership - If You Choose to Invest as a General Partner, Then You Have Greater Risk Than a Limited Partner" in the Prospectus.) Should cash distributions to a Participant from his Partnership exceed the tax basis of the Participant's Units, taxable gain would result to the Participant to the extent of the excess. (See "- Distributions From a Partnership," below.) "AT RISK" LIMITATION FOR LOSSES. Subject to the limitations on "passive losses" generated by a Partnership in the case of Limited Partners, and a Participant's basis in his Units, each Participant generally may use his share of the Partnership's losses to offset income from other sources. (See "- Limitations on Passive Activities" and "- Tax Basis of Units," above.) However, a Participant, other than a corporation which is neither an S corporation nor a corporation in which five or fewer individuals own more than 50% of the stock, who sustains a loss in connection with a Partnership's natural gas and oil activities may deduct the loss only to the extent of the amount he has "at risk" in the Partnership at the end of a taxable year. I.R.C. ss.465. "Loss" means the excess of allowable deductions for a taxable year from a Partnership over the amount of income actually received or accrued by the Participant during the year from the Partnership. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 18 A Participant's initial "at risk" amount generally is limited to the amount of money he pays for his Units. However, any amounts borrowed by a Participant to buy his Units will not be considered "at risk" if the amounts are borrowed from any person who has an interest, other than as a creditor, in the Partnership or from a related person to a person, other than the Participant, having such an interest. Also, the amount a Participant has "at risk" in a Partnership may not include the amount of any loss that the Participant is protected against through: o nonrecourse loans; o guarantees; o stop loss agreements; or o other similar arrangements. The amount of any loss that is disallowed will be carried over to the next taxable year, to the extent a Participant is "at risk" in the Partnership. Further, a Participant's "at risk" amount in subsequent taxable years of the Partnership will be reduced by that portion of the loss which is allowable as a deduction. Since income, gains, losses, and distributions of the Partnership affect the "at risk" amount, the extent to which a Participant is "at risk" must be determined annually. Previously allowed losses must be included in gross income if the "at risk" amount is reduced below zero. The amount included in income, however, may be deducted in the next taxable year to the extent of any increase in the amount which the Participant has "at risk" in the Partnership. DISTRIBUTIONS FROM A PARTNERSHIP. Generally, a cash distribution from a Partnership to a Participant in the Partnership in excess of the adjusted basis of the Participant's Units immediately before the distribution is treated as gain to the Participant from the sale or exchange of his Units to the extent of the excess. I.R.C. ss.731(a)(1). No loss is recognized by the Participants on these types of distributions. I.R.C. ss.731(a)(2). No gain or loss is recognized by the Partnership on these types of distributions. I.R.C. ss.731(b). If property is distributed by the Partnership to the Managing General Partner and the Participants, certain basis adjustments may be made by the Partnership, the Managing General Partner and the Participants. I.R.C. ss.ss.732, 733, 734, and 754. (See ss.5.04(d) of the Partnership Agreement and "- Tax Elections," below.) Other distributions of cash, disproportionate distributions of property, and liquidating distributions of a Partnership may result in taxable gain or loss to its Participants. (See "- Disposition of Units" and "- Termination of a Partnership," below.) SALE OF THE PROPERTIES. Under the Jobs and Growth Tax Relief Reconciliation Act of 2003 ("2003 Tax Act"), the maximum tax rates on a noncorporate taxpayer's adjusted net capital gain on the sale of assets held more than a year of 20%, or 10% to the extent it would have been taxed at a 10% or 15% rate if it had been ordinary income, have been reduced to 15% and 5%, respectively, for most capital assets sold or exchanged after May 5, 2003. In addition, for 2008 only, the 5% tax rate on adjusted net capital gain is reduced to 0%. The 2003 Tax Act also eliminated the former maximum tax rates of 18% and 8%, respectively, on qualified five-year gain. I.R.C. ss.1(h). The new capital gain rates also apply for purposes of the alternative minimum tax. I.R.C. ss.55(b)(3). (See "- Alternative Minimum Tax," below.) However, the former tax rates are scheduled to be reinstated January 1, 2009, as if the 2003 Tax Act had never been enacted. "Adjusted net capital gain" means net capital gain, less certain types of net capital gain that are taxed a maximum rate of 28% (such as gain on the sale of most collectibles and gain on the sale of certain small business stock); or 25% (gain attributable to real estate depreciation). "Net capital gain" means the excess of net long-term gain (excess of long-term gains over long-term losses) over net short-term loss (excess of short-term gains over short-term losses). The annual capital loss limitation for noncorporate taxpayers is the amount of capital gains plus the lesser of $3,000, which is reduced to $1,500 for married persons filing separate returns, or the excess of capital losses over capital gains. I.R.C. ss.1211(b). KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 19 Gains and losses from sales of natural gas and oil properties held for more than 12 months generally will be treated as a long-term capital gain, while a net loss will be an ordinary deduction, except to the extent of depreciation recapture on equipment and recapture of Intangible Drilling Costs and depletion deductions as discussed below. In addition, gain on the sale of a Partnership's natural gas and oil properties may be recaptured as ordinary income to the extent of certain losses for the five most recent preceding taxable years on previous sales, if any, of the Partnership's natural gas and oil properties or other assets. I.R.C. ss.1231(c). Other gains and losses on sales of natural gas and oil properties will generally result in ordinary gains or losses. Intangible Drilling Costs that are incurred in connection with a natural gas or oil property may be recaptured as ordinary income when the property is sold or otherwise disposed of in a taxable transaction by a Partnership. Generally, the amount recaptured is the lesser of: o the aggregate amount of expenditures which have been deducted as Intangible Drilling Costs with respect to the property and which, but for being deducted, would have been included in the adjusted basis of the property, plus deductions for depletion which reduced the adjusted basis of the property; or o the excess of: o the amount realized, in the case of a sale, exchange or involuntary conversion; or o the fair market value of the interest, in the case of any other taxable disposition; over the adjusted basis of the property. I.R.C.ss.1254(a). (See "- Intangible Drilling Costs" and "- Depletion Allowance," above.) In addition, all gain on the sale or other taxable disposition of equipment is treated as ordinary income to the extent of MACRS deductions claimed by the Partnership. I.R.C.ss.1245(a). (See "- Depreciation - Modified Accelerated Cost Recovery System ("MACRS"), above.) DISPOSITION OF UNITS. The sale or exchange, including a purchase by the Managing General Partner, of all or some of a Participant's Units held by him for more than 12 months generally will result in a recognition of long-term capital gain or loss. However, previous deductions for depreciation, depletion and Intangible Drilling Costs, and the Participant's share of the Partnership's "ss.751 assets" (i.e. inventory and unrealized receivables), may be recaptured as ordinary income rather than capital gain regardless of how long the Participant has owned his Units. (See "- Sale of the Properties," above.) If the Units are held for 12 months or less, the gain or loss generally will be short-term gain or loss. Also, a Participant's pro rata share of his 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 by a Participant may result in a tax liability to the Participant greater than the cash proceeds, if any, received by the Participant from the disposition. In addition to gain from a passive activity, a portion of any gain recognized by a Limited Partner on the sale or other taxable disposition of his Units will be characterized as portfolio income under ss.469 of the Code to the extent the gain is attributable to portfolio income, e.g. interest income on investments of working capital. Treas. Reg. ss.1.469-2T(e)(3). (See "- Limitations on Passive Activities," above.) KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 20 A gift of a Participant's Units may result in federal and/or state income tax and gift tax liability to the Participant. Also, interests in different partnerships do not qualify for tax-free like-kind exchanges. I.R.C. ss.1031(a)(2)(D). Other dispositions of a Participant's Units may or may not result in recognition of taxable gain. However, no gain should be recognized by an Investor General Partner on the conversion of his Investor General Partner Units to Limited Partner Units so long as there is no change in his share of his Partnership's liabilities or certain Partnership assets as a result of the conversion. Rev. Rul. 84-52, 1984-1 C.B. 157. A Participant who sells or exchanges all or some of his Units is required by the Code to notify the Partnership in which he invested within 30 days or by January 15 of the following year, if earlier. I.R.C. ss.6050K. After receiving the notice, the Partnership is required to make a return with the IRS stating the name and address of the transferor and the transferee, the fair market value of the portion of the Partnership's unrealized receivables and appreciated inventory allocable to the Units sold or exchanged (which is subject to recapture as ordinary income instead of capital gain) and any other information as may be required by the IRS. The Partnership must also provide each person whose name is set forth in the return a written statement showing the information set forth on the return. If a Participant dies, or sells or exchanges all of his Units, the taxable year of the Partnership in which he invested will close with respect to that Participant, but not the remaining Participants, on the date of death, sale or exchange, with a proration of partnership items for the Partnership's taxable year. I.R.C. ss.706(c)(2). If a Participant sells less than all of his Units, the Partnership's taxable year will not terminate with respect to the selling Participant, but his proportionate share of the Partnership's items of income, gain, loss and deduction will be determined by taking into account his varying interests in the Partnership during the taxable year. Deductions generally may not be allocated to a person acquiring Units from a selling Participant for a period before the purchaser's admission to the Partnership. I.R.C. ss.706(d). Participants are urged to consult their own tax advisors before any disposition of a Unit, including purchase of the Unit by the Managing General Partner. ALTERNATIVE MINIMUM TAX. With limited exceptions, taxpayers must pay an alternative minimum tax if it exceeds the taxpayer's regular federal income tax for the year. I.R.C. ss.55. For noncorporate taxpayers, the alternative minimum tax is imposed on alternative minimum taxable income that is above an exemption amount. Alternative minimum taxable income generally is taxable income, plus or minus various adjustments, plus tax preference items. The tax rate for noncorporate taxpayers is 26% for the first $175,000, $87,500 for married individuals filing separately, of a taxpayer's alternative minimum taxable income in excess of the exemption amount; and additional alternative minimum taxable income is taxed at 28%. However, the regular tax rates on capital gains also will apply for purposes of the alternative minimum tax. (See "- Sale of the Properties," above.) Subject to the phase-out provisions summarized below, the exemption amounts for 2004 are $58,000 for married individuals filing jointly, $40,250 for single persons and $29,000 for married individuals filing separately. For years beginning after 2004, these exemption amounts are scheduled to decrease to $45,000 for married individuals filing jointly, $33,750 for single persons, and $22,500 for married individuals filing separately. As of the date of the Prospectus, the U.S. House of Representatives had passed a bill that would extend the 2004 exemption amounts to 2005 and index them for inflation in following years. Whether that bill or other relief for taxpayers from the alternative minimum tax will become law in 2005 is uncertain. (See "- Changes in the Law," below.) The exemption amount for estates and trusts is $22,500 in 2004 and subsequent years. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 21 The exemption amounts are phased out for taxpayers with high alternative minimum taxable income. The exemption amounts are reduced by 25% of alternative minimum taxable income in excess of: o $150,000, in the case of married individuals filing a joint return and surviving spouses - the $58,000 exemption amount is completely phased out when alternative minimum taxable income is $382,000 or more, and the $45,000 amount phases out completely at $330,000; o $112,500, in the case of unmarried individuals other than surviving spouses - the $40,250 exemption amount is completely phased out when alternative minimum taxable income is $273,500 or more, and the $33,750 amount phases out completely at $247,500; and o $75,000, in the case of married individuals filing a separate return - the $29,000 exemption amount is completely phased out when alternative minimum taxable income is $191,000 or more and the $22,500 amount phases out completely at $165,000. In addition, in 2004 the alternative minimum taxable income of married individuals filing separately is increased by the lesser of $29,000 ($22,500 after 2004) or 25% of the excess of the person's alternative minimum taxable income (determined without regard to this provision) over $191,000 ($165,000 after 2004). Some of the principal adjustments to taxable income that are used to determine alternative minimum taxable income include: o Depreciation deductions may not exceed deductions computed using the 150% declining balance method, except as discussed above in "- Depreciation - Modified Accelerated Cost Recovery System ("MACRS")" with respect to "qualified" Tangible Costs of equipment in wells placed in service in 2004, if any, by Atlas America Public #14-2004 L.P. o Miscellaneous itemized deductions are not allowed. o Medical expenses are deductible only to the extent they exceed 10% of adjusted gross income. o State and local property and income taxes are not deductible. o Interest deductions are restricted. o The standard deduction and personal exemptions are not allowed. o Only some types of operating losses are deductible. o Different rules under the Code apply to incentive stock options that may require earlier recognition of income. The principal tax preference items that must be added to taxable income for alternative minimum tax purposes include: o Certain excess Intangible Drilling Costs, as discussed below. o Tax-exempt interest earned on certain private activity bonds. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 22 For taxpayers other than "integrated oil companies" as that term is defined in "- Intangible Drilling Costs," above, which does not include the Partnerships, the 1992 National Energy Bill repealed: o the preference for excess Intangible Drilling Costs; and o the excess percentage depletion preference for natural gas and oil. The repeal of the excess Intangible Drilling Costs preference, however, under current law may not result in more than a 40% reduction in the amount of the taxpayer's alternative minimum taxable income computed as if the excess Intangible Drilling Costs preference had not been repealed. I.R.C. ss.57(a)(2)(E). 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 natural gas and oil properties. Net natural gas and oil income is determined for this purpose without subtracting excess Intangible Drilling Costs. Excess Intangible Drilling Costs is the regular Intangible Drilling Costs deduction minus the amount that would have been deducted under 120-month straight-line amortization, or, at the taxpayer's election, under the cost depletion method. There is no preference item for costs of nonproductive wells. Also, each Participant may elect under ss.59(e) of the Code to capitalize all or part of his share of his Partnership's Intangible Drilling Costs and deduct the costs ratably over a 60-month period beginning with the month in which the costs were paid or incurred by the Partnership. This election also applies for regular tax purposes and can be revoked only with the IRS' consent. Making this election, therefore, generally will result in the following consequences to the Participant: o the Participant's regular tax deduction for Intangible Drilling Costs in the year in which he invests will be reduced because the Participant must spread the deduction for the amount of Intangible Drilling Costs which the Participant elects to capitalize over the 60-month amortization period; and o the capitalized Intangible Drilling Costs will not be treated as a preference that is included in the Participant's alternative minimum taxable income. Other than Intangible Drilling Costs as discussed above, the principal tax item that may have an impact on a Participant's alternative minimum taxable income as a result of investing in a Partnership is depreciation of the Partnership's equipment. Except for wells placed in service in 2004 by Atlas America Public #14-2004 L.P., if any, as noted above, if a Participant invests in that Partnership, each Partnership's cost recovery deductions for regular income tax purposes generally will be computed using the 200% declining balance method rather than the 150% declining balance method used for alternative minimum tax purposes. This means that in the early years of a Partnership a Participant's depreciation deductions from the Partnership generally will be smaller for alternative minimum tax purposes when compared to the Participant's depreciation deductions in those taxable years for regular income tax purposes on the same equipment. The rules relating to the alternative minimum tax for corporations are different than those summarized above. All prospective Participants contemplating purchasing Units in a Partnership are urged to consult with their own personal tax advisors as to the likelihood of them incurring or increasing any alternative minimum tax liability because of an investment in a Partnership. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 23 LIMITATIONS ON DEDUCTION OF INVESTMENT INTEREST. Investment interest expense is deductible by a noncorporate taxpayer only to the extent of net investment income each year, with an indefinite carryforward of disallowed investment interest. I.R.C. ss.163. Investment interest expense generally includes all interest on debt not incurred in a person's active trade or business except consumer interest, qualified residence interest, and passive activity interest under ss.469 of the Code. Accordingly, an Investor General Partner's share of any interest expense incurred by the Partnership in which he invests before his Investor General Partner Units are converted to Limited Partner Units will be subject to the investment interest limitation. In addition, the Investor General Partner's share of the Partnership's income and losses, including the deduction for Intangible Drilling Costs, will be considered to be investment income and losses for purposes of this limitation. Thus, for example, a loss allocated to the Investor General Partner from the Partnership in the year in which he invests in the Partnership as a result of the deduction for Intangible Drilling Costs will reduce his net investment income and may reduce or eliminate the deductibility of his investment interest expenses, if any, in that taxable year with the disallowed portion to be carried forward to the next taxable year. Net investment income is the excess of investment income over investment expenses. Investment income generally includes: o gross income from interest, rents, and royalties; o any excess of net gain from dispositions of investment property over net capital gain determined by gains and losses from dispositions of investment property, and any portion of the net capital gain or net gain, if less, that the taxpayer elects to include in investment income; o portfolio income under the passive activity rules, which includes working capital investment income; o dividends that do not qualify to be taxed at capital gain rates and dividends that the taxpayer elects to treat as not qualified to be taxed at capital gain rates; and o income from a trade or business in which the taxpayer does not materially participate if the activity is not a "passive activity" under ss.469 of the Code. In the case of Investor General Partners, this includes the Partnership in which they invest before the conversion of Investor General Partner Units to Limited Partner Units in that Partnership, and possibly Partnership net income allocable to former Investor General Partners after they are converted to Limited Partners in that Partnership. Investment expenses include deductions, other than interest, that are directly connected with the production of net investment income, including actual depreciation or depletion deductions allowable. Investment income and investment expenses, however, do not include income or expenses taken into account in computing income or loss from a passive activity under ss.469 of the Code. (See "- Limitations on Passive Activities," above.) ALLOCATIONS. The Partnership Agreement allocates to each Participant his share of his Partnership's income, gains, losses and deductions, including the deductions for Intangible Drilling Costs and depreciation. Allocations of certain items are made in ratios that are different than allocations of other items. (See "Participation in Costs and Revenues" in the Prospectus.) The Capital Accounts of the Participants are adjusted to reflect these allocations and the Capital Accounts, as adjusted, will be given effect in distributions made to the Participants on liquidation of the Partnership or any Participant's Units. Generally, the basis of the natural gas and oil properties owned by a Partnership for computation of cost depletion and gain or loss on disposition will be allocated and reallocated when necessary in the ratio in which the expenditure giving rise to the tax basis of each property was charged as of the end of the year. (See ss.5.03(b) of the Partnership Agreement.) Generally, a Participant's Capital Account in the Partnership in which he invests is increased by: o the amount of money he contributes to the Partnership; and KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 24 o allocations of income and gain to him from the Partnership; and decreased by: o the value of property or cash distributed to him by the Partnership; and o allocations of loss and deductions to him by the Partnership. The regulations also require that there must be a reasonable possibility that the allocation will affect substantially the dollar amounts to be received by the partners from the partnership, independent of tax consequences. Allocations made in a manner that is disproportionate to the respective interests of the partners in a partnership of any item of partnership income, gain, loss, deduction or credit will not be given effect unless the allocation has "substantial economic effect." I.R.C. ss.704(b). An allocation generally will have economic effect if throughout the term of a partnership: o the partners' capital accounts are maintained in accordance with rules set forth in the regulations, which generally are based on tax accounting principles; o liquidation proceeds are distributed in accordance with the partners' capital accounts; and o any partner with a deficit balance in his capital account following the liquidation of his interest in the partnership is required to restore the amount of the deficit to the partnership. Even though the Participants in each Partnership are not required under the Partnership Agreement to restore deficit balances in their Capital Accounts with additional Capital Contributions, an allocation which is not attributable to nonrecourse debt still will be considered under the regulations to have economic effect to the extent it does not cause or increase a deficit balance in a Participant's Capital Account if: o the Partners' Capital Accounts are maintained in accordance with rules set forth in the regulations, which generally are based on tax accounting principles; o liquidation proceeds are distributed in accordance with the Partners' Capital Accounts; and o the Partnership Agreement provides that a Participant who unexpectedly incurs a deficit balance in his Capital Account because of certain adjustments, allocations, or distributions will be allocated income and gain sufficient to eliminate the deficit balance as quickly as possible. Treas. Reg. ss.1.704-l(b)(2)(ii)(d). These provisions are included in the Partnership Agreement (See ss.ss.5.02, 5.03(h), and 7.02(a) of the Partnership Agreement.) Special provisions apply to deductions related to nonrecourse debt. If the Managing General Partner or an Affiliate makes a nonrecourse loan to a Partnership ("partner nonrecourse liability"), Partnership losses, deductions, or ss.705(a)(2)(B) expenditures attributable to the loan must be allocated to the Managing General Partner. Also, if there is a net decrease in partner nonrecourse liability minimum gain with respect to the loan, the Managing General Partner must be allocated income and gain equal to the net decrease. (See ss.ss.5.03(a)(1) and 5.03(i) of the Partnership Agreement.) KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 25 In the event of a sale or transfer of a Participant's Unit, the death of a Participant, or the admission of an additional Participant, a Partnership's income, gain, loss and deductions generally will be allocated among its Participants according to their varying interests in the Partnership during the taxable year. In addition, in the discretion of the Managing General Partner, Partnership property may be revalued on the admission of additional Participants, or if certain distributions are made to the Participants, to reflect unrealized income, gain, loss or deduction, inherent in the Partnership's property for purposes of adjusting the Participants' Capital Accounts. (See "- Tax Elections," below.) It should also be noted that each Participant's share of items of income, gain, loss and deduction in the Partnership in which he invests must be taken into account by him whether or not he receives any cash distributions from the Partnership. A Participant's share of Partnership revenues applied by his Partnership to the repayment of loans or the reserve for plugging wells, for example, will be included in his gross income in a manner analogous to an actual distribution of the income to him. Thus, a Participant may have tax liability on taxable income from his Partnership for a particular year in excess of any cash distributions from the Partnership to him with respect to that year. To the extent a Partnership has cash available for distribution, however, it is the Managing General Partner's policy that Partnership cash distributions will not be less than the Managing General Partner's estimate of the Participants' income tax liability with respect to that Partnership's income. If any allocation under the Partnership Agreement is not recognized for federal income tax purposes, each Participant's share of the items subject to the allocation generally will be determined in accordance with his interest in the Partnership in which he invests by considering all of the relevant facts and circumstances. To the extent deductions allocated by the Partnership Agreement exceed deductions which would be allowed under a reallocation by the IRS, Participants may incur a greater tax burden. However, 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 natural gas and oil properties, is substantial in light of a Participant's tax attributes that are unrelated to the Partnership in which he invests, in our opinion the allocations will have "substantial economic effect" and will govern the Participant's share of those items to the extent the allocations do not cause or increase a deficit balance in the Participant's Capital Account. PARTNERSHIP BORROWINGS. Under the Partnership Agreement the Managing General Partner and its Affiliates may make loans to the Partnerships. The use of Partnership revenues taxable to Participants to repay borrowings by their Partnership could create income tax liability for the Participants in excess of cash distributions to them 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 of the surrounding facts and circumstances. In Revenue Ruling 72-135, 1972-1 C.B. 200, the IRS ruled that a nonrecourse loan from a general partner to a partnership engaged in natural gas and oil exploration represented a capital contribution by the general partner rather than a loan. Whether a "loan" by the Managing General Partner or its Affiliates to a Partnership represents in substance debt or equity is a question of fact to be determined from all the surrounding facts and circumstances. PARTNERSHIP ORGANIZATION AND OFFERING COSTS. Expenses connected with the issuance and sale of the Units in the Partnerships, such as promotional expense, the Dealer-Manager fee, Sales Commissions, reimbursements to the Dealer-Manager and other selling expenses, professional fees, and printing costs, which are charged under the Partnership Agreement 100% to the Managing General Partner as Organization and Offering Costs, are not deductible. Although certain expenses incident to the creation of a partnership may be amortized over a period of not less than 60 months, these expenses also will be paid by the Managing General Partner as part of each Partnership's Organization and Offering Costs. Thus, any related deductions, which the Managing General Partner does not anticipate will be material in amount as compared to the total subscription proceeds in any Partnership, will be allocated to the Managing General Partner. I.R.C. ss.709; Treas. Reg. ss.ss.1.709-1 and 2. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 26 TAX ELECTIONS. Although each Partnership may elect to adjust the basis of its property (other than cash) on the transfer of a Unit in the Partnership by sale or exchange or on the death of a Participant, and on the distribution of property by the Partnership to a Participant (the ss.754 election), the Managing General Partner does not intend to make this election for any of the Partnerships. The general effect of this election is that transferees of the Units are treated, for purposes of depreciation and gain, as though they had acquired a direct interest in the Partnership assets and the Partnership is treated for these purposes, on certain distributions to the Participants, as though it had newly acquired an interest in the Partnership assets and therefore acquired a new cost basis for the assets. Any election, once made, may not be revoked without the consent of the IRS. As of the date of the Prospectus several bills were pending in Congress that proposed to make the ss.754 election mandatory for all partnerships. If the ss.754 election does become mandatory, the primary effect on a Partnership, other than the federal income tax consequences discussed above, would be an increase in its administrative and accounting expenses to make the required basis adjustments to its properties and separately account for those adjustments after they are made. (See "- Changes in the Law," below.) In this regard, the Partnerships generally will not make in-kind property distributions to their respective Participants, and the Units have not readily available market and are subject to substantial restrictions on their transfer. (See "Transferability of Units - Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement" in the Prospectus.) These factors will tend to limit the additional expense to a Partnership if the ss.754 election applies to it. Each Partnership also may make various elections for federal tax reporting purposes which could result in various items of income, gain, loss and deduction being treated differently for tax purposes than for accounting purposes. Code ss.195 permits taxpayers to elect to capitalize and amortize "start-up expenditures" over a 60-month period. These items include amounts: o paid or incurred in connection with: o investigating the creation or acquisition of an active trade or business; o creating an active trade or business; or o any activity engaged in for profit and for the production of income before the day on which the active trade or business begins, in anticipation of the activity becoming an active trade or business; and o which would be allowed as a deduction if paid or incurred in connection with the expansion of an existing business. Start-up expenditures do not include amounts paid or incurred in connection with the sale of the Units. If it is ultimately determined by the IRS or the courts that any of a Partnership's expenses constituted start-up expenditures, the Partnership's deductions for those expenses would be deferred over the 60-month period. TERMINATION OF A PARTNERSHIP. Under ss.708(b) of the Code, a Partnership will be considered as terminated for federal income tax purposes if within a 12-month period there is a sale or exchange of 50% or more of the total interest in Partnership capital and profits. The closing of the Partnership year may result in more than 12 months' income or loss of the Partnership being allocated to certain Participants for the year of termination, for example, in the case of any Participants using fiscal years other than the calendar year. Under ss.731 of the Code, a Participant will realize taxable gain on a termination of a Partnership to the extent that money regarded as distributed to him by the Partnership exceeds the adjusted basis of his Units. The conversion of Investor General Partner Units to Limited Partner Units, however, will not terminate a Partnership. Rev. Rul. 84-52, 1984-1 C.B. 157. Also, due to the restrictions on transfers of Units in the Partnership Agreement, the Managing General Partner does not anticipate that any Partnership will ever be considered as terminated under ss.708(b) of the Code. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 27 LACK OF REGISTRATION AS A TAX SHELTER. Section 6111 of the Code generally requires an organizer of a "tax shelter" to register the tax shelter with the Secretary of the Treasury, and to obtain an identification number which must be included on the individual federal income tax returns of investors in the tax shelter. For this purpose, a "tax shelter" generally is defined to include an investment with respect to which any person could reasonably infer that the ratio that: o 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; o the amount of money and the adjusted basis of property contributed to the investment; exceeds 2 to 1. In this regard, the Managing General Partner has determined that none of the Partnerships has a tax shelter ratio greater than 2 to 1. Accordingly, the Managing General Partner does not intend to register any of the Partnerships with the IRS as a tax shelter. If it is subsequently determined by the IRS or the courts that the Partnerships were required to be registered with the IRS as tax shelters, the Managing General Partner would be subject to certain penalties, including a penalty of 1% of the aggregate amount invested in each Partnership for failing to register and $100 for each failure to furnish a Participant a tax shelter registration number. Also, each Participant in that Partnership would be liable for a $250 penalty for failure to include a tax shelter registration number for the Partnership in which he invests on his individual federal income tax return unless the failure was due to reasonable cause. A Participant also would be liable for a penalty of $100 for failing to furnish the tax shelter registration number to any transferee of his Units. However, in our opinion none of the Partnerships is required to register with the IRS as a tax shelter. This opinion is based in part on the Managing General Partner's representations that none of the Partnerships has a tax shelter ratio greater than 2 to 1 and each Partnership will be operated as described in the Prospectus. 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. Under Section 6112 of the Code, if requested by the IRS a Partnership may be required to identify its Participants and provide the IRS with certain information concerning each Participant's investment in the Partnership and the tax benefits of the Partnership to the Participants, even though the Partnership is not registered with the IRS as a tax shelter. TAX RETURNS AND IRS AUDITS. The tax treatment of all partnership items generally is determined at the partnership, rather than the partner, level; and the partners generally are required to treat partnership items on their individual federal income tax returns in a manner which is consistent with the treatment of the partnership items on the partnership's federal information income tax return. I.R.C. ss.ss.6221 and 6222. Regulations define "partnership items" for this purpose as including distributive share items that must be allocated among the partners, such as partnership liabilities, data pertaining to the computation of the depletion allowance, and guaranteed payments. Treas. Reg. ss.301.6231(a)(3)-1. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 28 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 the Participants attributable to a partnership item generally may be extended by agreement between the IRS and the Managing General Partner, which will serve as each Partnership's representative ("Tax Matters Partner") in all administrative and judicial tax proceedings conducted at the partnership level. The Tax Matters Partner generally may enter into a settlement on behalf of, and binding on, any Participant owning less than a 1% profits interest in a Partnership if there are more than 100 partners in the Partnership. 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." I.R.C. ss.775. These rules also facilitate the matching of partnership items with individual partner federal income tax returns by the IRS. The Managing General Partner does not anticipate that the Partnerships will make this election. By executing the Partnership Agreement, each Participant agrees that he will not form or exercise any right as a member of a notice group and will not file a statement notifying the IRS that the Tax Matters Partner does not have binding settlement authority. All expenses of any proceedings involving the Managing General Partner as Tax Matters Partner, which might be substantial, will be paid for by the Partnership being audited. The Managing General Partner, however, is not obligated to contest adjustments made by the IRS. The Managing General Partner will notify the Participants of any IRS audits or other tax proceedings, and will provide the Participants any other information regarding the proceedings as may be required by the Partnership Agreement or law. TAX RETURNS. A Participant's individual income tax returns are the responsibility of the Participant. Each Partnership will provide its Participants with the tax information applicable to their investment in the Partnership necessary to prepare their tax returns. PENALTIES AND INTEREST. Interest is charged on underpayments of federal income tax and various penalties are included in the Code. PENALTY FOR NEGLIGENCE OR DISREGARD OF RULES OR REGULATIONS. If any portion of an underpayment of federal income tax is attributable to negligence or disregard of IRS rules or regulations, 20% of that portion is added to the tax. Negligence is strongly indicated if a Participant fails to treat partnership items on his individual federal income tax return in a manner that is consistent with the treatment of those items on his Partnership's federal information income tax return or to notify the IRS of the inconsistency. The term "disregard" includes any careless, reckless or intentional disregard of rules or regulations. There is no penalty, however, if the position (other than negligence) is adequately disclosed and has at least a reasonable basis, or the position is taken with reasonable cause and in good faith, or the position is contrary to an IRS ruling or notice but has a realistic possibility of being sustained on its merits. Treas. Reg. ss.ss.1.6662-3 and 1.6662-7. VALUATION MISSTATEMENT PENALTY. There is an addition to federal income tax of 20% of the amount of any underpayment of tax of $5,000 or more, $10,000 in the case of corporations other than S corporations or personal holding companies, which is attributable to a substantial valuation misstatement. There is a substantial valuation misstatement if: o the value or adjusted basis of any property claimed on a return is 200% or more of the correct amount; or o 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. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 29 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%. I.R.C.ss.6662(e) and (h). SUBSTANTIAL UNDERSTATEMENT PENALTY. There is also an addition to federal income 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: o 10% of the tax required to be shown on the return; or o $5,000, $10,000 in the case of corporations other than S corporations or personal holding companies. I.R.C. ss.6662(d). The amount of any understatement generally will be reduced to the extent it is attributable to the tax treatment of an item: o supported by substantial authority; or o adequately disclosed on the taxpayer's individual federal income return and there was a reasonable basis for the tax treatment. However, in the case of "tax shelters," which as defined by the Code for this purpose includes each Partnership, the understatement may be reduced by a taxpayer, other than a corporation, only if the tax treatment of an item attributable to a tax shelter was supported by substantial authority and the taxpayer establishes that he reasonably believed that the tax treatment claimed was more likely than not the proper treatment. I.R.C. ss.6662(d)(2)(C). Disclosure of partnership items should be made on each Partnership's federal information income tax return; however, a Participant also may make adequate disclosure on his individual federal income tax return with respect to pass-through items from the Partnership in which he invests. PROFIT MOTIVE, ANTI-ABUSE RULE AND JUDICIAL DOCTRINES. Under ss.183 of the Code, a Participant's ability to deduct his share of his Partnership's losses could be lost if the Partnership lacks the appropriate profit motive as determined from an examination of all facts and circumstances at the time. Section 183 of the Code creates a presumption that an activity is engaged in for profit if, in any three of five consecutive taxable years, the gross income derived from the activity exceeds the deductions attributable to the activity. Thus, if a Partnership fails to show a profit in at least three out of five consecutive years this presumption will not be available and the possibility that the IRS could successfully challenge the Partnership deductions claimed by its Participants 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 under ss.183 of the Code. (See Treas. Reg. ss.1.183-2(c), Example (5).) Under Treas. Reg. ss.1.701-2, 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 Code, based on all the facts and circumstances, the IRS is authorized to remedy the abuse. For illustration purposes, the following factors may indicate that a partnership is being used in a prohibited manner: o the partners' aggregate federal income tax liability is substantially less than had the partners owned the partnership's assets and conducted its activities directly; o the partners' aggregate federal income tax liability is substantially less than if purportedly separate transactions are treated as steps in a single transaction; KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 30 o one or more partners are needed to achieve the claimed tax results and have a nominal interest in the partnership or are substantially protected against risk; o substantially all of the partners are related to each other; o income or gain are allocated to partners who are not expected to have any federal income tax liability; o the benefits and burdens of ownership of property nominally contributed to the partnership are retained in substantial part by the contributing party; and o the benefits and burdens of ownership of partnership property are in substantial part shifted to the distributee partners before or after the property is actually distributed to the distributee partners. We also have considered the possible application to each Partnership and its intended activities of the potentially relevant judicial doctrines summarized below. o Step Transactions. This doctrine provides that where a series of transactions would give one tax result if viewed independently, but a different tax result if viewed together, then the IRS may combine the separate transactions. o Business Purpose. This doctrine involves a determination of whether the taxpayer has a business purpose, other than tax avoidance, for engaging in the transaction, i.e. a "profit objective." o Economic Substance. This doctrine requires a determination of whether, from an objective viewpoint, a transaction is likely to produce economic benefits in addition to tax benefits. This test is met if there is a realistic potential for profit when the investment is made, in accordance with the standards applicable to the relevant industry, so that a reasonable businessman, using those standards, would make the investment. o Substance Over Form. This doctrine holds that the substance of the transaction, rather than the form in which it is cast, governs. It applies where the taxpayer seeks to characterize a transaction as one thing, rather than another thing which has different tax results. Under this doctrine, the transaction must have practical economical benefits other than the creation of income tax losses. o Sham Transactions. Under this doctrine, a transaction lacking economic substance may be ignored for tax purposes. Economic substance requires that there be business realities and tax-independent considerations, rather than just tax-avoidance features, i.e. the transaction must have a reasonable and objective possibility of providing a profit aside from tax benefits. Shams include, for example, transactions entered into solely to reduce taxes, which is not a profit motive because there is no intent to produce taxable income. In our opinion, the Partnerships will possess the requisite profit motive under ss.183 of the Code, and the IRS anti-abuse rule in Treas. Reg. ss.1.701-2 and the potentially relevant judicial doctrines summarized above, will not have a material adverse effect on the tax consequences of an investment in a Partnership by a typical Participant as described in our opinions. These opinions are based in part on the results of the previous partnerships sponsored by the Managing General Partner as set forth in "Prior Activities" in the Prospectus and the Managing General Partner's representations. These representations include that each Partnership will be operated as described in the Prospectus (see "Management" and "Proposed Activities" in the Prospectus), and the principal purpose of each Partnership is to locate, produce and market natural gas and oil on a profitable basis, apart from tax benefits. These representations are supported by the geological evaluations and the other information for the Partnerships' proposed drilling areas and the specific Prospects proposed to be drilled by Atlas America Public #14-2004 L.P. included in Appendix A to the Prospectus. In addition, Appendix A will be supplemented or amended to cover a portion of the specific Prospects proposed to be drilled by Atlas America Public #14-2005(A) L.P. and Atlas America Public #14-2005(B) L.P. when Units in those Partnerships are offered to potential investors. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 31 STATE AND LOCAL TAXES. Each Partnership will operate in states and localities which impose a tax on its assets or its income, or on each of its Participants. The Partnerships also may be subject to state income tax withholding requirements on the Partnership or its Participants' share of the Partnership's income whether distributed to the Participants or not. Deductions which may be available to Participants for federal income tax purposes, may not be available for state or local income tax purposes. An example is the accelerated 50% first-year depreciation deduction discussed in "-Depreciation - Modified Accelerated Cost Recovery System ("MACRS") above. A Participant's share of the net income or net loss of the Partnership in which he invests generally must be included in determining his reportable income for state or local tax purposes in the jurisdiction in which he is a resident. To the extent that a non-resident Participant pays tax to a state because of Partnership operations within that state, he may be entitled to a deduction or credit against tax owed to his state of residence with respect to the same income. To the extent that the Partnership operates in certain jurisdictions, state or local estate or inheritance taxes may be payable on the death of a Participant in addition to taxes imposed by his own domicile. Prospective Participants are urged to consult with their own tax advisors concerning the possible effect of various state and local taxes on their personal tax situations resulting from an investment in a Partnership. SEVERANCE AND AD VALOREM (REAL ESTATE) TAXES. Each Partnership may incur various ad valorem or severance taxes imposed by state or local taxing authorities on its natural gas and oil wells and/or natural gas and oil production from the wells. SOCIAL SECURITY BENEFITS AND SELF-EMPLOYMENT TAX. A Limited Partner's share of income or loss from a 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 a Partnership will constitute "net earnings from self-employment" for these purposes. I.R.C. ss.1402(a). The ceiling for social security tax of 12.4% in 2004 is $87,900 and the ceiling for 2005 is not yet known. There is no ceiling for medicare tax of 2.9%. Self-employed individuals can deduct one-half of their self-employment tax. FARMOUTS. Under a Farmout by a Partnership, if a property interest, other than an interest in the drilling unit assigned to the Partnership Well in question, is earned by the farmee (anyone other than the Partnership) from the farmor (the Partnership) as a result of the farmee drilling or completing the well, then the farmee must recognize income equal to the fair market value of the outside interest earned, and the farmor must recognize gain or loss on a deemed sale equal to the difference between the fair market value of the outside interest and the farmor's tax basis in the outside interest. Neither the farmor nor the farmee would have received any cash to pay the tax. The Managing General Partner will attempt to eliminate or reduce any gain to a Partnership from a Farmout, if any. However, if the IRS claims that a Farmout by a Partnership results in taxable income to the Partnership and its position is ultimately sustained, the Participants in that Partnership would be required to include their share of the resulting taxable income on their personal income tax returns, even though the Partnership and its Participants received no cash from the Farmout. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. June 24, 2004 Page 32 FOREIGN PARTNERS. Each Partnership generally will be required to withhold and pay income tax to the IRS at the highest rate under the Code applicable to Partnership income allocable to its foreign Participants, even if no cash distributions are made to them. I.R.C. ss.1446. Also, a purchaser of a foreign Participant's Units may be required to withhold a portion of the purchase price and the Managing General Partner may be required to withhold with respect to taxable distributions of real property to a foreign Participant. These withholding requirements do not obviate United States tax return filing requirements for foreign Participants. In the event of overwithholding a foreign Participant must file a United States tax return to obtain a refund. Under ss.1441 of the Code, for withholding purposes a foreign Participant generally means a nonresident alien individual or a foreign corporation, partnership, trust or estate, if the Participant has not certified to his Partnership the Participant's nonforeign status. ESTATE AND GIFT TAXATION. There is no federal tax on lifetime or testamentary transfers of property between spouses. The gift tax annual exclusion in 2004 is $11,000 per donee, which will be adjusted in subsequent years for inflation. Under the Economic Growth and Tax Relief Reconciliation Act of 2001 (the "2001 Tax Act"), the maximum estate and gift tax rate of 48% in 2004 will be reduced in stages until it is 45% from 2007 through 2009. Estates of $1.5 million in 2004, which increases in stages to $3.5 million by 2009, or less generally are not subject to federal estate tax. Under the 2001 Tax Act, the federal estate tax will be repealed in 2010, and the maximum gift tax rate in 2010 will be 35%. In 2011 the federal estate and gift taxes are scheduled to be reinstated under the rules in effect before the 2001 Tax Act was enacted. CHANGES IN THE LAW. A Participant's investment in a Partnership may be affected by changes in the tax laws. (See "- Tax Elections," above.) For example, in 2003 the top four federal income tax brackets for individuals were reduced through December 31, 2010, including reducing the top bracket to 35% from 38.6%. The lower federal income tax rates will reduce to some degree the amount of taxes a Participant can save by virtue of his share of his Partnership's deductions for Intangible Drilling Costs, depletion and depreciation. On the other hand, the lower federal income tax rates also will reduce the amount of federal income tax liability incurred by a Participant on his share of the net income of his Partnership. There is no assurance that the federal income tax brackets discussed above will not be changed again before 2011. Prospective Participants are urged to consult with their own advisors with respect to the impact of recent legislation on an investment in a Partnership and the status of legislative, regulatory or administrative developments and proposals and their potential effect on an investment in a Partnership. We consent to the use of this letter as an exhibit to the Registration Statement, and all amendments to the Registration Statement, and to all references to this firm in the Prospectus. Very truly yours, /s/ Kunzman & Bollinger, Inc. KUNZMAN & BOLLINGER, INC. EX-10 9 ex-10a.txt EXHIBIT 10(A) Exhibit 10(a) FORM OF ESCROW AGREEMENT ATLAS AMERICA PUBLIC #14-_______ L.P. ATLAS AMERICA PUBLIC #14-____________ L.P. ESCROW AGREEMENT THIS AGREEMENT is made to be effective as of ________________, by and among Atlas Resources, Inc., a Pennsylvania corporation (the "Managing General Partner"), Anthem Securities, Inc., a Pennsylvania corporation ("Anthem"), Bryan Funding, Inc., a Pennsylvania corporation ("Bryan Funding"), collectively Anthem and Bryan Funding are referred to as the "Dealer-Manager," Atlas America Public #14-_________ L.P., a Delaware limited partnership (the "Partnership") and National City Bank of Pennsylvania, Pittsburgh, Pennsylvania, as escrow agent (the "Escrow Agent"). WITNESSETH: WHEREAS, the Managing General Partner intends to offer publicly for sale to qualified investors (the "Investors") up to 12,500 limited and investor general partner interests in the Partnership (the "Units"). WHEREAS, each Investor will be required to pay his subscription in full on subscribing by check or wire (the "Subscription Proceeds"). WHEREAS, the cost per Unit will be $10,000 subject to certain discounts of up to10.5% ($1,050 per Unit) for sales to the Managing General Partner, its officers, directors and affiliates, registered investment advisors and their clients, Selling Agents and their registered representatives and principals, and investors who buy Units through the officers and directors of the Managing General Partner. Also, the Managing General Partner, in its discretion, may accept one-half Unit ($5,000) subscriptions, with larger subscriptions permitted in $1,000 increments. WHEREAS, the Managing General Partner and Anthem have executed an agreement ("Anthem Dealer-Manager Agreement") under which Anthem will solicit subscriptions for Units in all states other than Minnesota and New Hampshire on a "best efforts" "all or none" basis for Subscription Proceeds of $2,000,000 and on a "best efforts" basis for the remaining Units on behalf of the Managing General Partner and the Partnership and under which Anthem has been authorized to select certain members in good standing of the National Association of Securities Dealers, Inc. ("NASD") to participate in the offering of the Units ("Selling Agents"). WHEREAS, the Managing General Partner and Bryan Funding have executed an agreement ("Bryan Funding Dealer-Manager Agreement") under which Bryan Funding will solicit subscriptions for Units in the states of Minnesota and New Hampshire on a "best efforts" "all or none" basis for Subscription Proceeds of $2,000,000 and on a "best efforts" basis for the remaining Units on behalf of the Managing General Partner and the Partnership and under which Bryan Funding has been authorized to select certain members in good standing of the NASD to participate in the offering of the Units ("Selling Agents"). WHEREAS, the Anthem Dealer-Manager Agreement and the Bryan Funding Dealer-Manager Agreement, collectively referred to as the "Dealer-Manager Agreement," provide for compensation to the Dealer-Manager to participate in the offering of the Units, subject to the discounts set forth above for certain Investors, which compensation includes, but is not limited to, for each Unit sold: o a 2.5% Dealer-Manager fee; o a 7% sales commission; 2 o a .5% accountable Reimbursement for Permissible Non-Cash Compensation; and o an up to .5% reimbursement of the Selling Agents' bona fide accountable due diligence expenses; all or a portion of which will be reallowed to the Selling Agents and wholesalers. WHEREAS, under the terms of the Dealer-Manager Agreement the Subscription Proceeds are required to be held in escrow subject to the receipt and acceptance by the Managing General Partner of the minimum Subscription Proceeds of $2,000,000, excluding any optional subscription by the Managing General Partner, its officers, directors, and Affiliates. WHEREAS, the Units may also be offered and sold by the officers and directors of the Managing General Partner without receiving a sales commission or other compensation on their sales. WHEREAS, no subscriptions to the Partnership will be accepted after the "Offering Termination Date," which is the first to occur of either: o receipt of the maximum Subscription Proceeds of $125,000,000; or o _____________________. WHEREAS, to facilitate compliance with the terms of the Dealer-Manager Agreement and Rule 15c2-4 adopted under the Securities Exchange Act of 1934, the Managing General Partner and the Dealer-Manager desire to have the Subscription Proceeds deposited with the Escrow Agent and the Escrow Agent agrees to hold the Subscription Proceeds under the terms and conditions set forth in this Agreement. NOW, THEREFORE, in consideration of the mutual covenants and conditions contained in this Agreement, the parties to this Agreement, intending to be legally bound, agree as follows: 1. APPOINTMENT OF ESCROW AGENT. The Managing General Partner, the Partnership, and the Dealer-Manager appoint the Escrow Agent as the escrow agent to receive and to hold the Subscription Proceeds deposited with the Escrow Agent by the Dealer-Manager and the Managing General Partner under this Agreement, and the Escrow Agent agrees to serve in this capacity during the term and based on the provisions of this Agreement. 2. DEPOSIT OF SUBSCRIPTION PROCEEDS. Pending receipt of the minimum Subscription Proceeds of $2,000,000, the Dealer-Manager and the Managing General Partner shall deposit the Subscription Proceeds of each Investor to whom they sell Units with the Escrow Agent and shall deliver to the Escrow Agent a copy of the "Subscription Agreement," which is the execution and subscription instrument signed by the Investor to evidence his agreement to purchase Units in the Partnership. Payment for each subscription for Units shall be in the form of a check or wire made payable to "Atlas America Public #14-______ L.P., Escrow Agent, National City Bank of Pennsylvania." 3. INVESTMENT OF SUBSCRIPTION PROCEEDS. The Subscription Proceeds shall be deposited in an interest bearing account maintained by the Escrow Agent as directed by the Managing General Partner. This may be a savings account, bank money market account, short-term certificates of deposit issued by a bank, or short-term certificates issued or guaranteed by the United States government. The interest earned shall be added to the Subscription Proceeds and disbursed in accordance with the provisions of Paragraph 4 or 5 of this Agreement, as the case may be. Escrow Agreement 3 4. DISTRIBUTION OF SUBSCRIPTION PROCEEDS. If the Escrow Agent: (a) receives proper written notice from an authorized officer of the Managing General Partner that at least the minimum Subscription Proceeds of $2,000,000 have been received and accepted by the Managing General Partner; and (b) determines that Subscription Proceeds for at least $2,000,000 are Distributable Subscription Proceeds; then the Escrow Agent shall promptly release and distribute to the Managing General Partner the Distributable Subscription Proceeds plus any interest paid and investment income earned on the Subscription Proceeds while held by the Escrow Agent in the escrow account. For purposes of the Agreement, "Distributable Subscription Proceeds" are Subscription Proceeds which have been deposited in the escrow account (1) by check, but only to the extent the Escrow Agent believes an amount of time has passed which would usually be sufficient for Subscription Proceeds paid by check to have returned unpaid by the bank on which the check was drawn and become Distributable Subscription Proceeds after a 10 day period from the date of deposit and (2) by wire transfer. After the occurrence of 4(a) and (b) above, Escrow Agent will provide a letter to the Managing General Partner confirming receipt of checks and/or wires representing Subscription Proceeds totaling at least $2,000,000 have been received and the anticipated date the funds will be considered Distributable Subscription Proceeds. After the initial distribution, any remaining Subscription Proceeds, plus any interest paid and investment income earned on the Subscription Proceeds while held by the Escrow Agent in the escrow account, shall be promptly released and distributed to the Managing General Partner by the Escrow Agent as the Subscription Proceeds become Distributable Subscription Proceeds after a 10 day period from the date of deposit. The Managing General Partner shall immediately return to the Escrow Agent any Subscription Proceeds distributed to the Managing General Partner or refunded to an Investor to the extent that such Subscription Proceeds were paid by a check which is returned or otherwise not collected for any reason prior or subsequent to termination of this Agreement. 5. SEPARATE PARTNERSHIP ACCOUNT. During the continuation of the offering after the Partnership is funded with cleared Subscription Proceeds of at least $2,000,000 and the Escrow Agent provides notice described in Paragraph 4 of this Agreement, and before the Offering Termination Date, any additional Subscription Proceeds may be deposited by the Dealer-Manager and the Managing General Partner directly in a separate Partnership account which shall not be subject to the terms of this Agreement. 6. DISTRIBUTIONS TO SUBSCRIBERS. (a) If the Partnership is not funded as contemplated because less than the minimum Subscription Proceeds of $2,000,000 have been received and accepted by the Managing General Partner by twelve (12:00) p.m. (noon), local time, EASTERN STANDARD TIME on the Offering Termination Date, or for any other reason, then the Managing General Partner shall notify the Escrow Agent, and the Escrow Agent promptly shall distribute to each Investor, for which Escrow Agent has a copy of a Subscription Agreement, a refund check made payable to the Investor in an amount equal to the Subscription Proceeds of the Investor, plus any interest paid or investment income earned on the Investor's Subscription Proceeds while held by the Escrow Agent in the escrow account. Escrow Agreement 4 (b) If a subscription for Units submitted by an Investor is rejected by the Managing General Partner for any reason after the Subscription Proceeds relating to the subscription have been deposited with the Escrow Agent, then the Managing General Partner promptly shall notify in writing, the Escrow Agent of the rejection, and the Escrow Agent shall promptly distribute to the Investor a refund check made payable to the Investor, for which Escrow Agent has a copy of a Subscription Agreement, in an amount equal to the Subscription Proceeds of the Investor, plus any interest paid or investment income earned on the Investor's Subscription Proceeds while held by the Escrow Agent in the escrow account. 7. COMPENSATION AND EXPENSES OF ESCROW AGENT. The Managing General Partner shall be solely responsible for and shall pay the compensation of the Escrow Agent for its services under this Agreement, as provided in Appendix 1 to this Agreement and made a part of this Agreement, and the charges, expenses (including any reasonable attorneys' fees), and other out-of-pocket expenses incurred by the Escrow Agent in connection with the administration of the provisions of this Agreement. The Escrow Agent shall have no lien on the Subscription Proceeds deposited in the escrow account unless and until the Partnership is funded with cleared Subscription Proceeds of at least $2,000,000 and the Escrow Agent receives the proper written notice described in Paragraph 4 of this Agreement, at which time the Escrow Agent shall have, and is granted, a prior lien on any property, cash, or assets held under this Agreement, with respect to its unpaid compensation and nonreimbursed expenses, superior to the interests of any other persons or entities. 8. DUTIES OF ESCROW AGENT. The Escrow Agent shall not be obligated to accept any notice, make any delivery, or take any other action under this Agreement unless the notice or request or demand for delivery or other action is in writing and given or made by the Managing General Partner or an authorized officer of the Managing General Partner. In no event shall the Escrow Agent be obligated to accept any notice, request, or demand from anyone other than the Managing General Partner. 9. LIABILITY OF ESCROW AGENT. The Escrow Agent shall not be liable for any damages, or have any obligations other than the duties prescribed in this Agreement in carrying out or executing the purposes and intent of this Agreement. However, nothing in this Agreement shall relieve the Escrow Agent from liability arising out of its own willful misconduct or gross negligence. The Escrow Agent's duties and obligations under this Agreement shall be entirely administrative and not discretionary. The Escrow Agent shall not be liable to any party to this Agreement or to any third-party as a result of any action or omission taken or made by the Escrow Agent in good faith. The parties to this Agreement will jointly and severally indemnify the Escrow Agent, hold the Escrow Agent harmless, and reimburse the Escrow Agent from, against and for, any and all liabilities, costs, fees and expenses (including reasonable attorney's fees) the Escrow Agent may suffer or incur by reason of its execution and performance of this Agreement. If any legal questions arise concerning the Escrow Agent's duties and obligations under this Agreement, then the Escrow Agent may consult with its counsel and rely without liability on written opinions given to it by its counsel. The Escrow Agent shall be protected in acting on any written notice, request, waiver, consent, authorization, or other paper or document which the Escrow Agent, in good faith, believes to be genuine and what it purports to be. If there is any disagreement between any of the parties to this Agreement, or between them or any other person, resulting in adverse claims or demands being made in connection with this Agreement, or if the Escrow Agent, in good faith, is in doubt as to what action it should take under this Agreement, then the Escrow Agent may, at its option, refuse to comply with any claims or demands on it or refuse to take any other action under this Agreement, so long as the disagreement continues or the doubt exists. In any such event, the Escrow Agent shall not be or become liable in any way or to any person for its failure or refusal to act and the Escrow Agent shall be entitled to continue to so refrain from acting until the dispute is resolved by the parties involved. Escrow Agreement 5 National City Bank of Pennsylvania is acting solely as the Escrow Agent and is not a party to, nor has it reviewed or approved any agreement or matter of background related to this Agreement, other than this Agreement itself, and has assumed, without investigation, the authority of the individuals executing this Agreement to be so authorized on behalf of the party or parties involved. 10. RESIGNATION OR REMOVAL OF ESCROW AGENT. The Escrow Agent may resign as such after giving thirty days' prior written notice to the other parties to this Agreement. Similarly, the Escrow Agent may be removed and replaced after receiving thirty days' prior written notice from the other parties to this Agreement. In either event, the duties of the Escrow Agent shall terminate thirty days after the date of the notice (or as of an earlier date as may be mutually agreeable); and the Escrow Agent shall then deliver the balance of the Subscription Proceeds (and any interest paid or investment income earned thereon while held by the Escrow Agent in the escrow account) in its possession to a successor escrow agent appointed by the other parties to this Agreement as evidenced by a written notice filed with the Escrow Agent. If the other parties to this Agreement are unable to agree on a successor escrow agent or fail to appoint a successor escrow agent before the expiration of thirty days following the date of the notice of the Escrow Agent's resignation or removal, then the Escrow Agent may petition any court of competent jurisdiction for the appointment of a successor escrow agent or other appropriate relief. Any resulting appointment shall be binding on all of the parties to this Agreement. On acknowledgment by any successor escrow agent of the receipt of the then remaining balance of the Subscription Proceeds (and any interest paid or investment income earned thereon while held by the Escrow Agent in the escrow account), the Escrow Agent shall be fully released and relieved of all duties, responsibilities, and obligations under this Agreement. 11. TERMINATION. This Agreement shall terminate and the Escrow Agent shall have no further obligation with respect to this Agreement after the distribution of all Subscription Proceeds (and any interest paid or investment income earned thereon while held by the Escrow Agent in the escrow account) as contemplated by this Agreement or on the written consent of all the parties to this Agreement. 12. NOTICE. Any notices or instructions, or both, to be given under this Agreement shall be validly given if set forth in writing and mailed by certified mail, return receipt requested, or by facsimile with confirmation of receipt (originals to be followed in the mail), or by a nationally recognized overnight courier, as follows: If to the Escrow Agent: National City Bank 1900 East 9th Street Cleveland, Ohio 44114 Attention: Dawn DeWerth LOC 2111 Phone: (216) 222-9225 Facsimile: (216) 222-7044 Escrow Agreement 6 If to the Managing General Partner: Atlas Resources, Inc. 311 Rouser Road P.O. Box 611 Moon Township, Pennsylvania 15108 Attention: Karen A. Black Phone: (412) 262-2830 Facsimile: (412) 262-2820 If to Anthem: Anthem Securities, Inc. 311 Rouser Road P.O. Box 926 Moon Township, Pennsylvania 15108 Attention: Justin T. Atkinson Phone: (412) 262-1680 Facsimile: (412) 262-7430 If to Bryan Funding: Bryan Funding, Inc. 393 Vanadium Road Pittsburgh, Pennsylvania 15243 Attention: Richard G. Bryan, Jr. Phone: (412) 276-9393 Facsimile: (412) 276-9396 Any party may designate any other address to which notices and instructions shall be sent by notice duly given in accordance with this Agreement. 13. MISCELLANEOUS. (a) This Agreement shall be governed by and construed in accordance with the laws of the Commonwealth of Pennsylvania. (b) This Agreement shall be binding on and shall inure to the benefit of the undersigned and their respective successors and assigns. (c) This Agreement may be executed in multiple copies, each executed copy to serve as an original. Escrow Agreement 7 14. The parties hereto and subscribers acknowledge Escrow Agent has not reviewed and is not making any recommendations with respect to the securities offered. IN WITNESS WHEREOF, the parties hereto have executed this Agreement to be effective as of the day and year first above written. NATIONAL CITY BANK OF PENNSYLVANIA As Escrow Agent By: --------------------------------- (Authorized Officer) ATLAS RESOURCES, INC. A Pennsylvania corporation By: --------------------------------- Karen A. Black, Vice President - Partnership Administration ANTHEM SECURITIES, INC. A Pennsylvania corporation By: --------------------------------- Justin T. Atkinson, President BRYAN FUNDING, INC. A Pennsylvania corporation By: --------------------------------- Richard G. Bryan, Jr., President ATLAS AMERICA PUBLIC #14-______ L.P. By: ATLAS RESOURCES, INC. Managing General Partner By: --------------------------------- Karen A. Black, Vice President - Partnership Administration Escrow Agreement 8 APPENDIX I TO ESCROW AGREEMENT COMPENSATION FOR SERVICES OF ESCROW AGENT REVIEW AND ACCEPTANCE FEE: $ WAIVED For providing initial review of the Escrow Agreement and all supporting documents and for initial services associated with establishing the Escrow Account. This is a one (1) time fee payable upon the opening of the account. I. Annual Administrative Fee Payable in Advance $3000.00 (or any portion thereof) II. Remittance of checks returned to subscribers 20.00 (set out in section 6 of the governing agreement) III. Wire transfers n/a IV. Purchase or Sale of Securities 100.00 V. Investments (document limits investment to a checking or savings account, or certificates of deposit) such products offered by any National City Bank retail branch)- fees are subject to the type of account the Managing General Partner directs the Escrow Agent to open and to be governed by the Escrow Agreement. EXTRAORDINARY SERVICES: For any services other than those covered by the aforementioned, a special per hour charge will be made commensurate with the character of the service, time required and responsibility involved. Such services include but are not limited to excessive administrative time, attendance at closings, specialized reports, and record keeping, unusual certifications, etc. Managing General Partner agrees to report all funds in accordance with appropriate tax treatment. FEE SCHEDULE IS SUBJECT TO ANNUAL REVIEW AND/or ADJUSTMENT UPON AMENDMENT THERETO. EX-10 10 ex-10c.txt EXHIBIT 10(C) EXHIBIT 10(c) GAS PURCHASE AGREEMENT DATED MARCH 31, 1999 BETWEEN NORTHEAST OHIO GAS MARKETING, INC., AND ATLAS ENERGY GROUP, INC., ATLAS RESOURCES, INC., AND RESOURCE ENERGY, INC. GAS PURCHASE AGREEMENT This Agreement made and entered into as of this 31st day of March, 1999, by and between Northeast Ohio Gas Marketing, Inc., an Ohio corporation ("Buyer") of P. O. Box 430, Lancaster, Ohio 43130-0430 and Atlas Energy Group, Inc., an Ohio corporation, Atlas Resources, Inc., a Pennsylvania corporation and Resource Energy, Inc., a Delaware corporation (collectively "Seller" of 311 Rouser Road, P.O. Box 611, Coraopolis, Pennsylvania 15108. RECITALS WHEREAS, Buyer utilizes volumes of natural gas, hereinafter referred to as "gas", for its customers situated in Ohio and Pennsylvania; and WHEREAS, Seller is in the business of developing and producing a supply of gas from gas and/or on wells situated in Ohio and Pennsylvania; and WHEREAS, Seller is the owner of such gas or is the authorized agent for the owner or owners of such gas and therefore has the authority to contract for the sale of such gas; and WHEREAS, Seller desires to sell and to agree to sell for itself and those owners for which it is the authorized agent, all of the gas produced from the wells, and Buyer desires to purchase such gas; and WHEREAS, as of the date hereof, FirstEnergy Trading and Power Marketing, Inc., an affiliate of Buyer, and AIC, Inc., an affiliate of Seller, are entering into an agreement (the "Stock Purchase Agreement') relating to the purchase of all of the common stock of Atlas Gas Marketing, Inc. NOW, THEREFORE, in consideration of the mutual covenants contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby expressly acknowledged, the parties do hereby agree as follows: 1. AGREEMENT: Subject to the terms of this Agreement, Seller does hereby agree to sell to Buyer on a firm basis and Buyer does hereby agree to purchase on a firm basis, during the continuing term of this Agreement, those quantities of natural gas described in. this Agreement. 2. TERM OF AGREEMENT: The term of this Agreement shall be effective for a primary term of ten (10) years commencing March 31, 1999 and terminating March 31, 2009. This Agreement shall automatically renew for successive annual terms unless either party, within one hundred twenty (120) days prior to the end of the primary term or any successive annual term, notifies the other party, in writing, of its intent to terminate this Agreement at the end of such term. The primary term and successive annual terms shall be considered the "term" of this Agreement. The price for gas for the first one (1) or two (2) years of the term 1 of this Agreement shall be set forth on Schedule I attached hereto. The price for gas for subsequent annual periods shall be agreed to between Buyer and Seller by November 30th of each subsequent year for the next succeeding annual period, which period shall commence on April 1st. Should the Buyer and Seller be unable to reach agreement as to the purchase price at any Point of Delivery, after the initial one or two year term, as applicable, or for any subsequent annual period, the Seller may solicit offers to purchase such gas from other third parties. In the event Seller should receive a bona fide offer to purchase all of Seller's gas, which is subject to this Agreement, at a specific Point of Delivery, it shall give notice (the "Notice") of the Point of Delivery, the name of prospective purchaser, the term of the proposed agreement and the purchase price to Buyer. If Buyer refuses to match such offer within five (5) business days of receipt of the Notice from Seller, then Seller shall be free to sell such gas to a party other than Buyer on the terms set forth in the Notice. Buyer's future rights to purchase such gas shall be restored at the completion of the term set forth in the Notice, subject to the provisions of this Paragraph. 3. DELIVERY POINT AND TRANSPORTATION: Subject to further provisions of this Agreement, and during the term hereof, any gas purchased hereunder shall be sold and delivered by Seller to Buyer at the interstate pipeline or local distribution company facilities of Tennessee Gas Pipeline Company, East Ohio Gas Company, National Fuel Gas Distribution, National Fuel Gas Supply, Peoples Natural Gas Company and Columbia Gas Transmission Corp., hereinafter be referred to as the "Points of Delivery". Additional Points of Delivery may be added by mutual agreement of Buyer and Seller. Title to the gas delivered hereunder shall vest to Buyer upon delivery by Seller to the Points of Delivery. Seller shall be responsible and pay for all gas transportation costs and retainage imposed by upstream pipelines to the Points of Delivery. As between the parties hereto, Seller shall be responsible for any damage or injury caused by the gas until the same shall have been delivered to the Points of Delivery after which delivery Buyer shall be in exclusive control and possession thereof and responsible for any damage or injury caused thereby. 4. QUANTITY: Seller shall exclusively make available to Buyer and Buyer agrees to purchase from Seller, during the term of this Agreement a quantity equal to 100% of the current and future production into the Points of Delivery. Except as otherwise provided in this Section, Seller shall deliver all gas it develops and produces into the Points of Delivery. Unless agreed to by Buyer Seller shall not sell any gas to any other party. It is currently estimated that Atlas Energy Group, Inc. and Atlas Resources, Inc. will collectively deliver approximately 27,000 Mcf per day and Resource Energy. Inc. will deliver approximately 7,000 Mcf per day at the Points of Delivery. Buyer and Seller agree to mutually cooperate and regularly meet to establish production schedules of gas into the Points of Delivery. Seller shall nominate, by the 25th calendar day of the preceding month, the daily volumes to be delivered during the following month to the Points of Delivery. Seller's daily deliveries shall be no greater than one hundred and ten percent (110%) or no less than ninety percent (90%) of Seller's daily nominated volume as long as Seller's deliveries at each Point of Delivery are at least 500 Mcf per day, with the exception of the Wheatland Dehydration Meter, for which the minimum volume is 300 Mcf per day. If Seller's daily volume delivery is less than ninety percent (90%) of Seller's daily nominated volume, then Seller's shall pay Buyer one hundred and two percent (102%) of the Buyer's replacement 2 cost, less the price set forth on Schedule I, for the volume of gas which is the difference between Seller's daily volume delivery and ninety percent (90%) of Seller's daily nominated volume. If Seller's daily volume delivery is more than one hundred and ten percent (110%) of Seller's daily nominated volume, then, regardless of other pricing provisions contained in this Agreement, Buyer shall pay Seller ninety eight percent (98%) of the daily market price of each Point of Delivery, as set forth on Schedule I, for the volume of gas which is the difference between Seller's daily volume delivery and one hundred and ten percent (110%) of Seller's daily nominated volume. Notwithstanding the first paragraph of this Section 4, it is understood and agreed to by the parties that Seller shall continue to supply gas to its three (3) direct delivery customers, Wheatland Tube Company, CSC Industries and Warren Consolidated for the life of those agreements, including any extensions or renewals. Buyer and Seller agree that Buyer will provide all billing services for the above three (3) customers. Buyer agrees that it will not utilize Seller's local production, or any other source of supply, as source of sales to the above three (3) customers of Seller to the extent Buyer's offer would supplant or in any manner displace the existing amount of Seller's direct delivery agreements throughout the term of Seller's agreements with the above three (3) customers, including any extensions or renewals. Seller currently delivers 2,600 Mcf per day to the Wheatland Tube Company, 3,400 Mcf per day to CSC Industries and 325 Mcf per day to Warren Consolidated. Seller agrees that Buyer may sell any amount, in excess of Seller's current volumes (so long as Seller continues to have a contact with the above three (3) customers) to such customers. Buyer shall not be restricted in selling to any of the above three (3) customers if Seller no longer has a contract with such customer. Seller's commitment to deliver all of the gas it produces to Buyer is subject to the right of investors, including limited partnerships where Seller is acting as the General Partner, in wells operated by Seller, to take their gas in kind. In the event a party wishes to take its gas in kind, Seller shall promptly notify Buyer. Seller further agrees to indemnify Buyer for full losses attributable to gas which has been taken in kind by investors in wells operated by Seller, to the extent Buyer has incurred a loss on such gas because of a prior commitment by Buyer. 5. PURCHASE PRICE: The price to be paid by Buyer to Seller for gas delivered to Buyer at the Point(s) of Delivery shall be as set forth on Schedule I attached hereto. 6. BILLING AND PAYMENT: Invoices shall be rendered to Buyer by the 14th calendar day of the month for gas delivered the preceding monthly period and payment shall be made monthly to Seller not later than the 28th calendar day of the month. Payment shall be made at the following address, or other address that may be designated by Seller from time to time: 311 Rouser Road, P.O. Box 611, Coraopolis, Pennsylvania 15108. Invoices shall be delivered to Buyer at: P.O. Box 430, Lancaster, Ohio 43130-0430. The quantities invoiced by Seller will be based on the quantities delivered by Seller at the Point(s) of Delivery. In the event the actual quantity delivered to the Point(s) of Delivery is unavailable, the estimated volumes of gas tendered for delivery by Seller to the Point(s) of Delivery shall be invoiced to Buyer. Any appropriate adjustment shall be made in the following billing period. Payment not received by the twenty-eighth (28th) calendar day of the month shall bear interest at PNC Bank, NA's then current prime lending rate minus two percent (2%). 3 7. QUALITY AND MEASUREMENT: Seller warrants that gas delivered under this Agreement shall meet the quality and measurement standards established by interstate pipeline and/or local distribution companies receiving gas from Seller for Buyer's account at the Point(s) of Delivery. 8. WARRANTY OF TITLE AND TAXES. Seller warrants title to all gas delivered by it and warrants that such gas is free from all liens and adverse claims. Seller shall indemnify and save Buyer harmless against all suits, debts, damages, costs and expenses arising from adverse claims to the gas delivered by it or taxes, payments or other charges thereon applicable before such gas is delivered to the Point(s) of Delivery. All present and future production, severance, gross proceeds or assessments of a similar nature imposed or levied by any state or other governmental agency or duly constituted authority upon the gas sold and delivered hereunder and the components thereof and the royalty, overriding royalty, production payment and other lease burden owners, as the case may be, shall be borne and paid by Seller. In the event Buyer is required to pay any of such taxes and assessments, Buyer may deduct same from the payments to be made by it hereunder and may make a reasonable charge for such service. Buyer shall be responsible for all taxes, liens and adverse claims which may be imposed on such gas after the Point(s) of Delivery. 9. REGULATORY BODIES. This Agreement and Buyer's and Seller's obligation hereunder shall be subject to all valid applicable State and Federal laws, and orders, directives, rules and regulations of any government body or official having jurisdiction hereunder. 10. NOTICES: Whenever under the terms of this Agreement, any notice is required or permitted to be given by one party to the other, it shall be given in writing and shall be deemed to have been sufficiently given for all purposes hereof if sent by telegram or mailed, postage prepaid, to the parties at the address set forth below: Seller: Atlas Energy Group. Inc. Atlas Resources, Inc. Resource Energy, Inc. Attn: Contract Administrator 311 Rouser Road P.O. Box 611 Coraopolis. Pennsylvania 15108 Buyer: Northeast Ohio Gas Marketing. Inc. Attn: Contract Administrator P. O. Box 430 Lancaster, Ohio 43130-0430 11. GOVERNING LAW: The interpretation and performance of this Agreement shall be in accordance with the laws of the State of Ohio. 12. FORCE MAJEURE: If either Buyer or Seller is rendered unable, wholly or in part, by force majeure to perform its obligations under this Agreement, other than the obligation to make payments then or thereafter due, it is agreed that performance of the respective obligations of the parties hereto to deliver 4 and receive gas, so far as they are affected by such force majeure, shall be suspended from the inception of any such inability until it is corrected, but for no longer period. The party claiming such inability shall give notice thereof to the other party as soon as practicable after the occurrence of the force majeure. If such notice is first given by telephone communications, it shall be confirmed promptly in writing giving full particulars. The party claiming such inability shall promptly correct such inability to the extent it may be corrected through the exercise of reasonable diligence. Force majeure as used herein shall mean acts of God, vandalism, war, civil disturbance, rebellion, blockade, strike or other labor dispute, lightning, fire, flood, explosion, hurricane, freezing of wells or pipelines which result in the failure of third party pipelines to transport gas hereunder, permanent plant closing of either the Carbide Graphite plant or the Duferco Farrell Corporation plant (during the term of the existing agreement with such party, excluding any extensions or renewals) and other causes not within the control of the party claiming a force majeure situation. 13. ASSIGNMENT: Neither party may assign any of its rights under this Agreement without the prior written consent of the other party, which will not be unnecessarily withheld, except that Buyer may assign any of its rights under this Agreement to any affiliate of Buyer, provided that Buyer remains responsible for all financial obligations hereunder. Subject to the preceding sentence, this Agreement will apply to, be binding in all respects upon, and inure to the benefit of the successors and permitted assigns of the parties. 14. SURVIVAL OBLIGATIONS: The obligation of Buyer to make payment hereunder shall survive the termination or cancellation of this Agreement. The obligations of Seller to indemnify Buyer pursuant to the provisions set forth under Section 8 shall survive the termination or cancellation of this Agreement. If any provision in this Agreement is determined to be invalid, void, or made unenforceable by any court having jurisdiction, then such determination shall not invalidate, void or make unenforceable any other provision, agreement or covenant in this Agreement. No waiver of any breach of this Agreement shall be held to be a waiver of any other or subsequent breach. All remedies afforded in this Agreement shall be taken and construed as cumulative, that is, in addition to every other remedy provided therein or by law. 15. COMPLETE AGREEMENT: This Agreement, and the Stock Purchase Agreement, represent the complete and entire understanding between the parties and their affiliates respecting the subject matter of this transaction. The parties hereto declare that there are no promises, representations, conditions, warranties or other agreements, express or implied, oral or written, made or relied upon by either party, except those contained herein or in the Stock Purchase Agreement. 5 IN WITNESS WHEREOF, the parties. or their authorized agent, hereto have caused this Agreement to be executed on this the 31st day of March, 1999. Witnesses: Seller: Atlas Energy Group, Inc. _______________________________ By: _______________________________ _______________________________ Title: ____________________________ Witnesses: Seller: Atlas Resources, Inc. _______________________________ By: _______________________________ _______________________________ Title: ____________________________ Witnesses: Seller: Resource Energy, Inc. _______________________________ By: _______________________________ _______________________________ Title: ____________________________ Witnesses: Buyer: Northeast Ohio Gas Marketing, Inc. _______________________________ By: _______________________________ _______________________________ Title: ____________________________ 6 AMENDMENT TO GAS PURCHASE AGREEMENT THIS AMENDMENT, dated as of February 1, 2001, by and between Atlas Resources, Inc., a Pennsylvania corporation, Atlas Energy Group, Inc., an Ohio corporation, and Resource Energy, Inc., a Delaware corporation (hereinafter collectively referred to as "Seller"), and FirstEnergy Services Corp., an assign of Northeast Ohio Gas Marketing, Inc. ("Buyer"). WHEREAS, Buyer and Seller are parties to an Agreement dated March 31, 1999 (the "Agreement"), concerning the sale and purchase of natural gas; and WHEREAS, Viking Resources Corporation ("Viking"), is in the business of developing and producing natural gas from wells in Ohio and Pennsylvania, and recently became an affiliate of Seller; and WHEREAS, Viking is the owner of such natural gas or is the authorized agent for the owner of such natural gas and therefore has the authority to contract for the sale of such natural gas; and WHEREAS, as an inducement for Buyer to establish a Guaranty to Seller from Buyer's parent, FirstEnergy Corp., Viking has offered to sell for itself and those owners for which it is the authorized agent all of the gas produced at the meters identified on Exhibit A attached hereto, and Buyer offered to purchase such natural gas from Viking; NOW, THEREFORE, in consideration of the mutual covenants herein, and other good and valuable consideration, the Seller and Buyer do hereby agree to amend the Agreement to include the purchase and sale of Viking's natural gas production at the meters identified on Exhibit A. This Amendment shall become effective upon execution by the parties. All other terms and conditions of the Agreement shall remain in full force and effect. 1 IN WITNESS WHEREOF, the parties have hereunto set their corporate signatures by their duly authorized officers as of the day and year first above written. WITNESS: SELLERS: ATLAS RESOURCES, INC. ATLAS ENERGY GROUP, INC. RESOURCE ENERGY, INC. VIKING RESOURCES CORPORATION __________________________ ___________________________ By: WITNESS: BUYER: FIRSTENERGY SERVICES CORP. __________________________ ___________________________ By: 2 SECOND AMENDMENT TO BASE GAS PURCHASE AGREEMENT Dated July 16, 2003 Between FirstEnergy Solutions Corp. and Atlas Energy Group, Inc., Atlas Resources, Inc. and Resource Energy, Inc. The criteria for the Amendment are as follows: WHEREAS, Atlas Energy Group, Inc., Atlas Resources, Inc. and Resource Energy, Inc. (Seller) and FirstEnergy Solutions Corp. (Buyer) have entered into a Gas Purchase Agreement dated March 31, 1999 (Agreement), and whereas the parties desire to implement certain amendments to the Base Agreement as set forth herein; WHEREAS, Seller represents that it is the owner of the Gas or is the authorized agent for the owner or owners of the Gas and therefore has the authority to contract for the delivery and sale of the Gas, and WHEREAS, Buyer and Seller are parties to an Amendment to the Agreement dated February 1, 2001, concerning the purchase and sale of Viking Resource Corporation's natural gas production; Now, therefore, in consideration of the mutual covenants and promises set forth below, the parties hereto, intending to be legally bound, hereby covenant, promise and agree as follows: 1. In exchange for a corporate guaranty or other credit assurance reasonably acceptable in form and substance to the Buyer, Seller may, at any time prior to Noon on the day of the applicable NYMEX Contract closing day, notify an authorized representative of Buyer by telephone to execute financial hedging instruments at a mutually agreed price ("Hedge Price") then-currently traded for that month ("Hedge Month") on a specified volume ("Hedge Volume"). If Buyer agrees to exercises the Hedge described in the previous sentence, Buyer will send a written notice to the Seller to confirm the Hedge Price and Hedge Volume for the respective Hedge Month. Thereafter, the Hedge Price shall serve in lieu of any Floating Contract Price specified in the Transaction Confirmation for Gas delivered in the Hedge Month up to the Contract Hedge Volume. Contract Hedge Volume shall be defined as any portion (in 10,000 Dth increments) of the volume that the Seller is obligated to deliver pursuant to a specified Transaction Confirmation. If Seller delivers less than One Hundred (100) Percent of the Contract Hedge Volume for a given Hedge Month and the Contract Hedge Price is lower than the NYMEX Contract Settlement Price (as determined on the last day of trading allowed by NYMEX for the respective contract month), Seller shall be assessed a Market Differential Cost equal to (the NYMEX Contract Settlement Price minus Contract Hedge Price), multiplied by the undelivered Contract Hedge Volume. The Market Differential Cost shall apply to the underproduction of Seller's Contract Hedge Volume, but shall not apply to the underproduction of Seller's daily nominated gas volumes. In the event of Seller's underproduction of daily nominated gas volumes, Seller shall be assessed the replacement costs set forth in paragraph 4 of the Agreement 2. Seller shall deposit with Buyer a commercial letter of credit in the aggregate amount of $1,000,000, which letter of credit shall be in the form attached hereto as Exhibit A and issued by a commercial bank acceptable to 1 Buyer, payable on presentation by Buyer to such bank of one or more sight drafts in form acceptable to Buyer. The letter of credit to be deposited and maintained with Buyer shall be held by Buyer as security for the full faith and performance and observance by Seller of each and every term, covenant, and condition of the Agreement as amended. Concurrent with the delivery of the above referenced letter of credit by the Seller to the Buyer, Buyer shall deliver to Seller a parental corporate guaranty reasonably acceptable in form and substance to the Seller, guaranteeing the payment in the amount fifteen million dollars ($15,000,000) in the event of non-payment by Buyer of any amounts due and owing Seller under the Agreement and/or the Second Amendment to the Agreement. The term of Buyer's parental guaranty shall be for the identical term of the letter of credit Seller deposits with Buyer. This guaranty shall supercede any existing parental guaranty that Buyer has delivered to Seller. 3. This Letter of Credit may be drawn upon if an Event of Default occurs. Event of Default shall mean the Applicant (the "Defaulting Party") or its guarantor fails to perform any obligation under the Gas Purchase Agreement dated March 31, 1999, including Seller's failure to pay Buyer, within forty five (45) days upon receipt of an invoice, for any assessed Market Differential Costs for Seller's underproduction of natural gas resulting in a net negative impact to Buyer. IN WITNESS WHEREOF, the parties have hereunto set their signatures by their officers hereunto duly authorized the day and year first above written. FirstEnergy Solutions Corp. Atlas Energy Group, Inc. Atlas Resources, Inc. Resource Energy, Inc. _______________________________ By: _________________________ Dated: ________________________ Dated: July 16, 2003 2 Exhibit A (Proposed form of Letter of Credit) Beneficiary Applicant FirstEnergy Solutions Corp. ________________________________ 395 Ghent Road ________________________________ Akron, OH 44333 ________________________________ Attn: 1. We hereby issue our irrevocable Letter of Credit (this "Letter of Credit") No. __________ in your favor for $_____________________ U.S. Dollars available for payment at sight in immediately available funds. This Letter of Credit is issued at the request of the Applicant, and we hereby irrevocably authorize you to draw on us, in accordance with the terms and conditions hereof, up to the maximum amount of this Letter of Credit. This Letter of Credit may be drawn upon an Event of Default under the Second Amendment to Base Gas Purchase Agreement dated July ___, 2003 between FirstEnergy Solutions Corp. and Atlas Energy Group, Inc., Atlas Resources, Inc. and Resource Energy, Inc. 2. A partial or full drawing hereunder may be made by you on any Business Day prior to the expiration of this Letter of Credit by delivering, by no later than 11:00 A.M. (New York, NY) on such Business Day to Bank _____________________, _________________________ (address), (i) a notice executed by you in the form of Annex 1 hereto, appropriately completed and duly signed by your Authorized Officer and (ii) your draft in the form of Annex 2 hereto, appropriately completed and duly signed by your Authorized Officer. Authorized Officer shall mean President, Treasurer, any Vice President or any Assistant Treasurer. 3. This Letter of Credit expires at the counters of _____________ on ______________ (which date as may be extended in the manner provided herein is referred to as the "termination date"). The termination date shall be deemed automatically extended without amendments for one year from the initial termination date and thereafter for one year from each anniversary of the initial termination date unless at least ninety (90) days prior to the then applicable termination date we notify you in writing by certified mail return receipt requested that we are not going to extend the termination date. During said ninety (90) day period, this Letter of Credit shall remain in full force and effect. 4. We hereby agree with the beneficiary drawers, endorsers, and bona fide holders of drafts and documents drawn under and in compliance with the terms and conditions of this Letter of Credit that same will be duly honored by us upon presentation to ourselves as specified, by payment in accordance with the beneficiary's payment instructions. If requested by the beneficiary, payment under this Letter of Credit will be made by wire transfer of immediately available funds to the beneficiary's account at any financial institution located in the Continental United States. All payments under this Letter of Credit will be made in our own funds. 3 5. This Letter of Credit is subject to the ICC Uniform Customs and Practice for Documentary Credits (1993 Revision) International Chamber of Commerce Publication Number 500, or any revisions thereto. 6. We will send via facsimile a copy of this Letter of Credit to the beneficiary at the following facsimile number: _____________, attention: __________________, and we will send via overnight courier the original of this Letter of Credit to the beneficiary at the above address, attention of: _______________________. 7. All bank charges are for the account of _____________________. 8. This letter of credit is transferable and assignable in whole or in part by beneficiary. (Signed) 4 Annex 1 to Letter of Credit DRAWING UNDER LETTER OF CREDIT NO. ________________ ______________________, 200__ To: (Bank) (Address) Attention: Standby Letter of Credit Unit Ladies and Gentlemen: The undersigned is making a drawing under the above-referenced Letter of Credit in the amount specified below and herby certifies to you as follows: 1. Capitalized terms used herein are defined herein shall have the meanings ascribed thereto in the Letter of Credit. 2. Pursuant to Paragraph 2 of the Letter of Credit No. _____________, dated _____________, 200__, the undersigned is entitled to make a drawing under the Letter of Credit in the amount of $________________, inasmuch as there is an Event of Default under the Second Amendment to Base Gas Purchase Agreement dated July ___, 2003 between the Applicant and us. 3. We acknowledge that, upon your honoring the drawing herein requested, the amount of the Letter of Credit available for drawing shall be automatically decreased by an amount equal to this drawing. Very truly yours, FirstEnergy Solutions Corp. By: _________________________ Name: Title: Date: Cc: ____________________- (Applicant) 5 Annex 2 to Letter of Credit DRAWING UNDER LETTER OF CREDIT NO. ___________ ___________________, 200__ ON [Business Day immediately succeeding date of presentation] PAY TO: FirstEnergy Solutions Corp. Attn: $________________________ For credit in the amount of $____________________________. FOR VALUE RECEIVED AND CHARGE TO ACCOUNT OF LETTER OF CREDIT NO. ___________ OF (Bank) (Address) FirstEnergy Solutions Corp. By: ___________________________ Name: Title: 6 EX-10 11 ex-10d.txt EXHIBIT 10(D) Exhibit 10(d) GUARANTY DATED AUGUST 12, 2003 BETWEEN FIRST ENERGY CORP. AND ATLAS RESOURCES, INC. TO GAS PURCHASE AGREEMENT DATED MARCH 31, 1999 BETWEEN NORTHEAST OHIO GAS MARKETING, INC., AND ATLAS ENERGY GROUP, INC., ATLAS RESOURCES, INC., AND RESOURCE ENERGY, INC. FirstEnergy(R) 76 South Main St. Akron, Ohio 44308 - -------------------------------------------------------------------------------- 1-800-633-4766 Guaranty dated as of August 12, 2003 by and between FirstEnergy Corp., an Ohio corporation, with its principal place of business at 76 South Main Street, Akron, OH 44308 ("Guarantor") and Atlas Resources Inc., a Pennsylvania corporation, with its principal place of business at 311 Rouser Rd., Coraopolis, PA 15108 ("Seller"). Seller, together with its affiliates Atlas Energy Group, Inc., an Ohio Corporation, Resource Energy, Inc., a Delaware corporation, and Viking Resources Corporation, an Ohio Corporation, entered into a Gas Purchase Agreement for the purchase and sale of natural gas ("Sales Agreement") to FirstEnergy Solutions Corp.,("Customer"), a subsidiary of the Guarantor. In consideration thereof, and as an inducement for the extension of credit by the Seller to the Customer, the Guarantor hereby absolutely and unconditionally guarantees to the Seller, its permitted successors and assigns pursuant to this letter (this "Guaranty"), the prompt payment (within three (3) business days of demand by the Seller) of any and all amounts that are or may hereafter become due and payable (taking into account all applicable grace periods) from the Customer to the Seller by reason of the Sales Agreement (the "Obligations"), to fully perform the Sales Agreement, as well as any indebtedness under the Sales Agreement (regardless of whether such indebtedness be in the form of book accounts, promissory notes, trade acceptances, checks, drafts, or other evidence of indebtedness, together with late fees, service charges or liquidated damages (but only if, and to the extent, provided for in the Sales Agreement) and interest at the rate specified therein) This Guaranty shall be a guaranty of payment, and not of collection, and the Seller shall not be required to take any proceedings or exhaust its remedies against the Customer prior to the exercise of its rights and remedies against the Guarantor, as guarantor. The Guarantor hereby agrees to reimburse the Seller for all sums paid to it by the Customer under the Sales Agreement, which must subsequently be returned by the Seller to the Customer as a preference or fraudulent transfer under the Federal Bankruptcy Code, any applicable state law and for any other reason. Notwithstanding anything else in this Guaranty to the contrary, the obligation and liability of Guarantor hereunder shall not (i) be effective or enforceable with respect to any Obligation, liability or claim relating in any way to consequential, indirect, punitive or exemplary damages of any kind whatsoever, whether owing by Company or otherwise, and (ii) exceed Fifteen Million Dollars ($15,000,000) in the aggregate. This Guaranty is a continuing guaranty and shall remain in full force and effect from August 12, 2002 until at least March 31, 2005, and shall continue on a monthly basis thereafter, unless terminated by either party with thirty (30) days written notice to the other party. If the Guarantor shall be adjudicated bankrupt under the Federal Bankruptcy Laws, or if any petition for any relief under any of such laws shall be filed by or against the Guarantor, or if the Guarantor shall make an assignment for the benefit of creditors or shall apply for a receiver for all or any part of its property, or if the Guarantor shall become insolvent or unable to pay its debts as they mature, then and in any such event all of the Obligations shall forthwith become and be immediately due and payable by the Guarantor. Notice of demand by the Seller shall be sent by either certified mail, return receipt requested, or hand delivery, to the respective addresses specified above, with notices to the Guarantor sent to the attention of the Credit Manager and notices to the Seller sent to the attention of both John Ranieri and Nancy McGurk, and shall be deemed to be received on the day that such writing is delivered to the intended recipient thereof. 1 The Guarantor hereby acknowledges that any modification of the Sales Agreement shall not affect the liability of the Guarantor with respect hereto. Except as provided above with respect to the requirement of notice from the Seller to the Guarantor of a payment demand, the Guarantor hereby waives, to the extent permitted by law, the requirements of the giving of any notice, including, but not limited to, (a) notice of the acceptance of this Guaranty by the Seller; (b) notice of the entry into the Sales Agreements between the Customer and the Seller and of any modifications thereto; (c) notice of any extension of time for the payment of any sums due and payable to the Seller under the Sales Agreement; (d) with respect to any notes or evidence of indebtedness received by the Seller from the Customer, notice of presentment, notice of adverse facts, protest or notice of protest; and (e) notice of any defaults by or disputes with the Customer. This Guaranty shall not be affected by the taking of any checks, notes or other obligations, secured or unsecured, in any amount, purportedly in payment of the whole or any part of any Obligations or by reason of any extension of time given to, or any indulgences shown to, the Customer by the Seller, or by the making, execution and delivery of any oral or written agreement or agreements affecting said Obligations. The Guarantor's liability hereunder shall not be impaired or discharged by reason of any reorganization, insolvency, bankruptcy or similar proceeding (whether voluntary or involuntary) modifying the Seller's rights and remedies against the Customer with regard to any Obligation or liability of the Customer to the Seller under the Sales Agreement. The Guarantor also waives diligence, presentment, protest to or upon Customer with respect to the Obligations. This Guaranty shall be construed as a continuing, absolute and unconditional guarantee of payment without regard to (a) the validity, regularity or enforceability of the Sales Agreement, any of the Obligations or any other collateral security therefor or guarantee a right of offset with respect thereto at any time or from time to time by Seller, (b) until Seller shall have been paid in full, any right by Guarantor to subrogation of indemnification, or (c) any other circumstance whatsoever (with or without notice to or knowledge of the Seller or Guarantor) which constitutes, or might be construed to constitute, an equitable or legal discharge of the Customer for the Obligations, or of Guarantor under this Guaranty, in bankruptcy or in any other instance. When pursuing its rights and remedies hereunder against Guarantor, the Seller may, but shall be under no obligation to, pursue such rights and remedies as it may have against Customer or any other party or against any collateral security or guarantee for the Obligations or any right to offset with respect thereto, and any failure by Seller to pursue such other rights or remedies or to collect any payments from the Customer or any such other party or to realize upon any such collateral security or guarantee or to exercise any such right of offset, or any release of Customer or any such other party or of any such collateral security, guarantee or right of offset, shall not relieve Guarantor of any liability hereunder, and shall not impair or affect the rights and remedies, whether express, implied or available as a matter of law, of Seller against Guarantor. Notwithstanding anything else in this Guaranty to the contrary, Guarantor shall be permitted and entitled to raise all defenses to payment hereunder that are available to Company, other than those defenses available to the Company solely as a result of bankruptcy, insolvency, reorganization and other similar proceedings. This Guaranty shall bind the Guarantor for any and all of the Customer's purchases of natural gas from the Seller, or the Seller's production affiliates, Resource Energy, Inc., Viking Resources Corporation, and Atlas Energy Group, Inc. This Guaranty shall remain in full force and effect and be binding in accordance with and to the extent of its terms upon Guarantor and its successors and assigns thereof, and shall inure to the benefits of the Seller, and its respective successors, transferees, affiliates and assigns, until all Obligations and the obligations of Guarantor under this Guaranty shall been satisfied by payment in full. The Guarantor represents and warrants, as the date hereof, that this Guaranty has been duly authorized, executed and delivered by the Guarantor. 2 This Guaranty shall not be assigned or modified without the written consent of each of the Guarantor and the Seller and shall not be affected by any change in the relationship between Guarantor and the Customer. This Guaranty shall not be relied upon, or enforced, by any person other than the Guarantor, the Customer, and the Seller. This Guaranty shall be governed by and construed in accordance with the laws of the State of Ohio, without regard to the conflict of law rules thereof. The Guarantor and the Seller, by accepting this Guaranty, submit to the non-exclusive jurisdiction of the Courts of the State of Ohio and the United States District Court of Northern District of Ohio. This Guaranty revokes any prior guaranty issued by the Guarantor to the Seller for the obligations of the Customer. IN WITNESS WHEREOF, the Guarantor has caused this Guaranty to be executed by its duly authorized officer as of the date first above written. FIRSTENERGY CORP. Randy Scilla ----------------------- Randy Scilla Assistant Treasurer 3 EX-10 12 ex-10e.txt EXHIBIT 10(E) EXHIBIT 10(e) MASTER NATURAL GAS GATHERING AGREEMENT DATED FEBRUARY 2, 2000 AMONG ATLAS PIPELINE PARTNERS, L.P. AND ATLAS PIPELINE OPERATING PARTNERSHIP, L.P., ATLAS AMERICA, INC., RESOURCE ENERGY, INC., AND VIKING RESOURCES CORPORATION MASTER NATURAL GAS GATHERING AGREEMENT THIS MASTER NATURAL GAS GATHERING AGREEMENT is made as of February 2, 2000, among ATLAS PIPELINE PARTNERS, L.P., a Delaware limited partnership, and ATLAS PIPELINE OPERATING PARTNERSHIP, L.P., a Delaware limited partnership (collectively, "Gatherer"), ATLAS AMERICA, INC., a Delaware corporation ("Atlas America"), RESOURCE ENERGY, INC., a Delaware corporation ("Resource Energy"), and VIKING RESOURCES CORPORATION, a Pennsylvania corporation ( "Viking Resources," and collectively with Atlas America and Resource Energy, "Shipper"). Recitals: A. Gatherer owns a natural gas gathering system and related facilities consisting of approximately 888 miles of pipelines located in New York, Ohio and Pennsylvania, and operated as a private use gathering system as more particularly described in Exhibit A (as same may be added to or extended, the "Gathering System"). B. Shipper has now or may in the future form affiliates for purposes of carrying on Shipper's energy industry business. For purposes of this Agreement, (i) "Affiliate" means, with respect to any person, any other person that, directly or indirectly, through one or more intermediaries, controls, is controlled by or is under common control with the person in question; and (ii) the term "control" means (a) direct or indirect beneficial ownership of 50% or more of the voting securities or voting interest of a person or, in the case of a limited partnership, of 50% or more of the general partnership interest, either directly or through an entity which the person controls or (b) the possession of the power to direct the management of a person, whether through contract or otherwise; provided, however, that Investment Programs (as such term is hereinafter defined) shall not be deemed to be Affiliates of Shipper for purposes of this Agreement. C. Shipper and Affiliates own interests in certain wells connected to the Gathering System, which are more particularly described in Exhibit B ("Shipper's Existing Well Interests"). D. Shipper and Affiliates may drill additional wells, acquire interests in other wells or operate (with the authority to determine natural gas gathering arrangements) other wells (excluding Future Investment Program Well Interests, as such term is hereinafter defined), connect them to the Gathering System or a Third Party Gathering System (as such term is hereinafter defined) after the date of this Agreement in accordance with the terms of the Omnibus Agreement (as such term is hereinafter defined) ("Shipper's Future Well Interests"). E. Shipper and Affiliates have agreements or other arrangements with respect to the gathering of natural gas from interests in wells owned by third parties and connected to the Gathering System as of the date of this Agreement, including well interests owned by Investment Programs (as such term is hereinafter defined), which are more particularly described in Exhibit C ("Existing Third Party Well Interests"). F. Shipper and Affiliates have sponsored or may in the future sponsor Investment Programs (as such term is hereinafter defined) which, on or after December 1, 1999, have drilled or may in the future drill wells or acquire interests in other wells and connect them to the Gathering System or connect them to Third Party Gathering Systems (as such term is hereinafter defined) all as more particularly provided for in the Omnibus Agreement (including wells for which drilling has commenced on or after December 1, 1999, "Future Investment Program Well Interests"). G. Gatherer and Shipper desire to provide for the gathering and redelivery of the gas produced from Shipper's Existing Well Interests, Shipper's Future Well Interests, Existing Third Party Well Interests and Future Investment Program Well Interests ("Shipper's Gas"), all as more fully provided herein. NOW, THEREFORE, in consideration of the premises, and the mutual covenants and agreements herein set forth, and intending to be legally bound, the parties agree as follows: Article 1. DEFINITIONS Unless otherwise defined herein, the following terms shall have the following meanings: "Agreement" means this Master Natural Gas Gathering Agreement, as it may be amended, modified or supplemented from time to time. "Common Units" means common units of limited partnership interest of Atlas Pipeline Partners, L.P. "Day" means a period of time beginning at 7:00 a.m., Eastern Time, on each calendar day and ending at 7:00 a.m., Eastern Time, on the next succeeding calendar day. "Delivery Points" means the points on the Gathering System described in Exhibit D-1. Exhibit D-1 will be revised from time to time to reflect any additional Delivery Points that may be established as a result of the Omnibus Agreement or as may be otherwise agreed to by Shipper and Gatherer. "Force Majeure Event" means any act of God, strike, lockout, or other industrial disturbance, act of a public enemy, sabotage, war (whether or not an actual declaration is made thereof), blockade, insurrection, riot, epidemic, landslide, lightning, earthquake, flood, storm, fire, washout, arrest and restraint of rules and peoples, civil disturbance, explosion, breakage or accident to machinery or line or pipe, hydrate obstruction of line or pipe, lack of pipeline capacity, repair, maintenance, improvement, replacement, or alteration to plant or line of pipe or related facility, failure or delay in transportation, temporary failure of gas supply or markets, freezing of the well or delivery facility, well blowout, cratering, partial or entire failure of the gas well, the act of any court, agency or governmental authority, or any other cause, whether of the kind enumerated or otherwise, not within the reasonable control of the party claiming suspension. 2 "General Partner" means Atlas Pipeline Partners GP, LLC, a Delaware limited liability company. "Gross Sale Price" shall mean the price, per mcf, actually received by the Seller for natural gas sold by it, without deduction for brokerage fees, commissions or offsets. "Investment Program" means a Person for whom Shipper or a direct or indirect subsidiary of Shipper acts as a general partner, managing partner or manager and the securities of which have been offered and sold to investors. "mcf" means one thousand (1,000) cubic feet of gas measured at a base temperature of sixty degrees (60(Degree)) Fahrenheit and at a pressure base of fourteen and seventy-three one-hundredths (14.73) psia. "mmcf" means one million (1,000,000) cubic feet of gas measured at a base temperature of sixty degrees (60(Degree)) Fahrenheit and at a pressure base of fourteen and seventy-three one-hundredths (14.73) psia. "Omnibus Agreement" means the Omnibus Agreement among Gatherer and Shipper of even date herewith. "Partnership Agreement" means the First Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P. of even date herewith. "Person" means an individual, corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association or other entity. "psia" means pounds per square inch absolute. "psig" means pounds per square inch gauge. "Receipt Points" means the points on the Gathering System described in Exhibit D-2. Exhibit D-2 will be revised from time to time to reflect any additional Receipt Points that may be established as a result of the Omnibus Agreement or as may be otherwise agreed to by Shipper and Gatherer. "Shipper's Field Fuel" means Shipper's allocated share of actual Gathering System fuel requirements, shrinkage, and lost and unaccounted for gas. Such allocations shall be based upon the proportion volume of natural gas that Shipper's Gas bears to the aggregate gathered by Gatherer during the relevant period. 3 "Third Party Gathering System" means a natural gas gathering system owned by a Person other than Gatherer or a subsidiary of Gatherer. Article 2. GATHERING SERVICES 2.1. Receipt of Gas. Subject to the terms, limitations, and conditions of this Agreement, Shipper dedicates, and will cause its Affiliates to dedicate, to this Agreement, and agrees, and will cause its Affiliates to agree, to deliver exclusively to the Receipt Points, and Gatherer agrees to accept at the Receipt Points, on a fully interruptible basis, all of Shipper's Gas; provided, however, that Gatherer shall only be obligated to accept on any Day for gathering hereunder that volume of Shipper's Gas which Gatherer determines, in its sole discretion, it has available capacity to receive. 2.2. Redelivery of Gas. Gatherer will gather, compress, and redeliver, on a fully interruptible basis, to the Delivery Points, and Shipper will accept, a quantity of gas equal, on a mcf basis, to the quantity of Shipper's Gas received at the Receipt Points less Shipper's Field Fuel. 2.3. Shipper's Field Fuel. Shipper's Field Fuel will be calculated monthly by Gatherer by allocating such quantities of actual Gathering System fuel requirements, shrinkage, and lost and unaccounted for gas between all shippers using the Gathering System. Gatherer may retain and use Shipper's Field Fuel as fuel for compression and other operations on the Gathering System. 2.4. Commingling Shipper's Gas. Gatherer shall have the right to commingle Shipper's Gas with other natural gas in the Gathering System. Gatherer may extract, or permit to be extracted, from Shipper's Gas condensate to the extent necessary to meet the quality requirements of the receiving pipeline at the Delivery Points or for proper functioning of the Gathering System. Article 3. TITLE AND LIABILITY 3.1. Shipper's Gas. Except for Shipper's Field Fuel and products removed in treating Shipper's Gas, title to Shipper's Gas shall remain with Shipper or, with respect to Shipper's Gas from Existing Third Party Well Interests, the owners of such wells. 3.2. Adverse Claims. Shipper shall indemnify, hold harmless and defend Gatherer, the General Partner and the officers, agents, employees and contractors of Gatherer and the General Partner (each, an "Indemnified Person") against any liability, loss or damage whatsoever, including costs and attorneys fees (collectively, a "Loss"), suffered by an Indemnified Person, where such Loss arises, directly or indirectly, out of any demand, claim, action, cause of action or suit brought by any Person asserting ownership of or an interest in Shipper's Gas. 4 3.3. Possession and Control. As between the parties hereto, Gatherer shall be deemed to be in control and possession of Shipper's Gas after Gatherer receives Shipper's Gas at any Receipt Point and until Shipper's Gas is delivered at any Delivery Point; provided, however, that Gatherer shall not, by any such possession and control, be deemed to have title to Shipper's Gas it receives. Shipper shall be deemed to be in control and possession of Shipper's Gas at all other times. 3.4. Indemnity. The party deemed to be in control and possession of Shipper's Gas shall be responsible for and shall indemnify the other party with respect to any Losses arising in connection with or related to Shipper's Gas when it is in the indemnifying party's control and possession; provided, that no party shall be responsible for any Losses arising from the other party's negligence or breach of this agreement. Article 4. DELIVERY PRESSURE 4.1. Receipt Points. Shipper shall deliver Shipper's Gas at a pressure sufficient to effect delivery into the Gathering System at the Receipt Points, but not in excess of the maximum pressure specified by Gatherer from time to time. 4.2. Compression. Gatherer shall maintain all existing compression facilities, unless Shipper shall otherwise consent in writing, and shall install such additional compression facilities as may be necessary or appropriate under good industry practices and commercially reasonable. 4.3. Wellhead Equipment. With respect to Shipper's Existing Well Interests, Shipper's Future Well Interests and Future Investment Program Well Interests, Shipper shall install, operate and maintain, at its sole expense, all wellhead and pressure regulating equipment necessary to prevent Shipper's delivery pressure at the Receipt Point from exceeding the maximum pressure specified by Gatherer from time to time. 4.4. Inspection. Gatherer shall have the right at any time, but not the obligation, to inspect Shipper's facilities at the Receipt Points, and Gatherer may immediately cease accepting Shipper's Gas if the pressure in Shipper's facilities exceeds the maximum pressure reasonably established by Gatherer from time to time, or require Shipper to install equipment necessary to limit the pressure to such maximum. Article 5. GAS QUALITY 5.1. Minimum Specifications. Shipper's Gas delivered into the Gathering System shall be commercially free from liquids of any kind, air, dust, gum, gum forming constituents, harmful or noxious vapors, or other solid or liquid matter which, in the sole judgment of Gatherer, may interfere with the merchantability of Shipper's Gas or cause injury to or interfere with proper operation of the lines, regulators, meters or other equipment of the Gathering System. Shipper's Gas shall also conform to applicable quality specifications of the receiving pipeline at each applicable Delivery Point. 5 5.2. Suspension. Gatherer may, at its option, (i) refuse to accept delivery of any Shipper's Gas not meeting the above-described quality specifications or (ii) accept delivery of all or any part of Shipper's Gas (notwithstanding the deficiency in quality) and in such event Shipper shall be responsible for all damages to the Gathering System, including costs of repair, due to its failure to comply with such quality specifications. Article 6. MEASUREMENT AND TESTING 6.1. Measurement Equipment. Measurement of Shipper's Gas shall take place at the Receipt Points. Shipper will install, or cause to be installed, at or near the Receipt Points, orifice meters or other measuring equipment necessary in Gatherer's judgment to accurately measure the volumes of Shipper's Gas being delivered into the Gathering System to the extent such meters or other measuring equipment have not been installed as of the date of this Agreement. Such measuring equipment shall be comparable to the measuring equipment of other parties delivering gas into the Gathering System. Shipper shall be responsible for, and bear the cost of, acquiring, installing, maintaining and operating such measurement equipment. 6.2. Chart Integration. Gatherer shall be responsible for reading the meters at the Receipt Points. Gatherer shall furnish, install, remove, and integrate all recording charts used in such meters in accordance with Gatherer's standard practices. 6.3. Delivery Points. The measurement of and tests for quality of Shipper's Gas redelivered at the Delivery Points shall be governed by and determined in accordance with the requirements of the receiving pipeline at each Delivery Point. 6.4. Unit of Volume. The unit of volume for purposes of measurement shall be one (1) cubic foot of gas at a temperature base of sixty degrees (60(Degree)) Fahrenheit and at a pressure base of fourteen and seventy-three one-hundredths (14.73) psia. 6.5. Testing Procedures. Shipper shall follow the meter calibrations schedule established by Gatherer for each meter on the Gathering System. Such calibrations shall occur at least once every twelve (12) months but not more frequently than once every six (6) months. No testing, calibration, or adjustment of a meter or related equipment shall be performed without Gatherer first being given five (5) days' notice thereof and having the opportunity to be present. 6.6. Meter Inaccuracy. If, at any time, any meter is found to be out of service or registering inaccurately in any percentage, it shall be adjusted at once by Shipper to read accurately within the limits prescribed by the meter's manufacturer. If such equipment is out of service or inaccurate by an amount exceeding three percent (3%) of a reading corresponding to the average flow rate for the period since the last test, the previous readings shall be corrected for the period that the meter is known to be inaccurate, or, if not known, a period of one-half (1/2) the elapsed time since the last test. The volume of Shipper's 6 Gas delivered during such period shall be estimated by Gatherer either (i) by using the data recorded by any check measuring equipment if installed and accurately registered, (ii) by correcting the error if the percentage of error is ascertainable by calibration, test, or mechanical calculation or, if neither such method is feasible, (iii) by estimating the quantity delivered based upon deliveries under similar conditions during a period when the equipment registered accurately. No volume correction shall be made for metering inaccuracies of three percent (3%) or less. 6.7. Meter Testing. If Gatherer requests to have any meter tested, then Shipper shall have the meter tested in the presence of and to the satisfaction of Gatherer. If the meter tested proves to be accurate within plus or minus three percent (3%) at its normal operating range, then the cost of testing and recalibrating the meter shall be borne by Gatherer. Shipper will schedule all required tests within ten (10) days of a request by Gatherer. Shipper will notify Gatherer at least five (5) working days prior to the test of the date, time, and location of such test. 6.8. Books and Records. Gatherer shall keep and maintain proper books of account during the term of this Agreement and for a period of three (3) years thereafter showing (a) the total volume of Shipper's Gas transported through the Gathering System from the Receipt Points to the Delivery Points and (b) the volume of gas allocated to each Receipt Point. Gatherer shall also preserve, or cause to be preserved, for at least one (1) year all test data, charts, and similar data pertaining to the measurement and testing of Shipper's Gas, unless a longer period is prescribed by applicable regulations. Shipper shall have the right during normal business hours, after reasonable notice to Gatherer, to inspect Gatherer's books and records not older than three (3) years from the date of request for inspection. Such inspections shall take place at Gatherer's office. Any costs attributable to such audits or inspections shall be borne by Shipper. Article 7. GATHERING FEES 7.1. Consideration. As consideration for Gatherer's gathering Shipper's Gas, Atlas America and Resource Energy, jointly and severally, shall pay to Gatherer one of the following fees, as applicable. 7.2. Gathering Fees For Gathering Production from Existing Third Party Well Interests, Shipper's Future Well Interests and Future Investment Program Well Interests. The gathering fees for gathering production from Existing Third Party Well Interests, Shipper's Future Well Interests and, except as set forth in Section 7.4 hereof, Future Investment Program Well Interests shall be the greater of Thirty Five Cents for each mcf ($0.35/mcf) delivered by Shipper at the Receipt Points and sixteen percent (16%) of the Gross Sale Price for each such mcf. 7.3. Gathering Fee For Gathering Production From Shipper's Existing Well Interests. The gathering fees for gathering production from Shipper's Existing Well Interests shall be the greater of Forty Cents for each mcf ($0.40/mcf) delivered by Shipper at the Receipt Points and sixteen percent (16%) of the Gross Sale Price for each such mcf. 7 7.4. Fees Payable to Gatherer for Shipper's Future Well Interests in Wells Not Connected to the Gathering System. In the event that Shipper shall connect Shipper's Future Well Interests or Future Investment Program Well Interests to a Third Party Gathering System pursuant to Section 2.3.3(ii) of the Omnibus Agreement and Gatherer shall assume the cost of constructing that connection, Shipper shall pay Gatherer a fee that shall be equal to the excess, if any, of the greater of (i) Thirty Five Cents for each mcf ($0.35/mcf) delivered by Shipper at the Receipt Points for the Third Party Gathering System and sixteen percent (16%) of the Gross Sale Price for each such mcf, over (ii) the gathering fees charged by the Third Party Gathering System. 7.5. Assignment of Rights and Obligations; Agreement to Fees by Affiliates. Viking Resources assigns to Atlas America and Resource Energy, and shall cause its Affiliates to assign to Atlas America and Resource Energy, all of their rights and obligations under and pursuant to gathering arrangements between the Affiliate or Viking Resources and owners of Existing Third Party Well Interests. Article 8. BILLING AND PAYMENT 8.1. Statements and Payments. In connection with fees payable to Gatherer under Article 7 of this Agreement, Gatherer shall prepare and submit to Shipper each month a statement showing for the prior month (i) the volume of Shipper's Gas received at the Receipt Points, (ii) Shipper's Field Fuel, and (iii) the volume of Shipper's Gas delivered to the Delivery Points. Shipper shall provide Gatherer, within thirty (30) days after the end of each month, a statement of the gathering fees due for such month. Shipper's statement shall set forth (i) the volumes of Shipper's Gas for which payments have been received; (ii) an allocation of such Shipper's Gas among the three gathering fee categories established by Sections 7.2, 7.3 and 7.4, respectively; (iii) an itemization of the Gross Sale Price or Prices received for the Shipper's Gas in each category; and (iv) a calculation of the gathering fees for such Shipper's Gas. Gatherer shall have the right to inspect Shipper's books and records relating to such Shipper's Gas for purposes of verifying the accuracy of Shipper's statement. Gatherer shall advise Shipper within 30 days of Gatherer's receipt of Shipper's statement if Gatherer believes Shipper's statement to be inaccurate in any respect. If Gatherer does not so advise Shipper, Shipper's statement shall be deemed to be correct. The gathering fee shall be due and payable upon Gatherer's receipt of Shipper's statement. Each of Gatherer and Shipper shall preserve its records relating to any statement delivered pursuant to this Section 8.1 for a period of at least three (3) years after such statement is delivered. 8.2. Payment Default. If Shipper fails to pay Gatherer in accordance with Section 8.1, Gatherer may, at its option and without limiting any other remedies, either, singularly or in combination, (i) terminate this Agreement forthwith and without notice or (ii) suspend performance under this Agreement until all indebtedness under this Agreement is paid in full. 8 8.3. Overdue Payments. Any overdue balance shall accrue daily interest charges at the rate equal to the lesser of (i) 15% per annum or (ii) the maximum lawful rate of interest. 8.4. Remittance of Revenues. If any revenues for sales of Shipper's Gas are paid directly to Gatherer, Gatherer shall remit such revenues to Shipper within fifteen (15) days; provided, however, that Gatherer may offset from any such revenues any amounts as shall then be due and payable to Gatherer under this Agreement. 8.5. Gathering Fees Payable to Shipper. Shipper shall have sole and exclusive responsibility for settling with all Persons having an interest in Shipper's Gas and collecting gathering fees payable to Shipper with respect thereto. Shipper's obligations hereunder shall be without regard to receipt or collection by Shipper of any such fees. Article 9. TERM 9.1. Term. Subject to the other provisions of this Agreement, this Agreement shall become effective as of its date and shall remain in effect so long as gas is produced from any of Shipper's Existing Well Interests, Shipper's Future Well Interests, Future Investment Program Well Interests or Existing Third Party Well Interests in economic quantities without a lapse of more than ninety (90) days. 9.2. Uneconomic Operation. Notwithstanding anything contained herein to the contrary, if at any time Gatherer determines, in its sole discretion, that continued operation of all or any part of the Gathering System is not economically justified, Gatherer may cease receiving Shipper's Gas from the relevant part of the Gathering System and terminate this Agreement as to such part of the Gathering System (the "Terminated System") by giving at least ninety (90) days' notice to Shipper. In such event, and concurrently with such notice, Gatherer shall offer Shipper the right to purchase the Terminated System from Gatherer for $10.00. Shipper shall exercise such right on or before sixty (60) days after receipt of the termination notice. Shipper shall be responsible for all costs and expenses related to such purchase, including filing fees, and such purchase shall be without recourse, representation or warranty. Closing on the purchase shall be on the day specified in the termination notice as the termination date. If the Terminated System is acquired by Shipper and remains connected to any other portion of the Gathering System, Shipper shall have the right to deliver natural gas from the Terminated System to the Gathering System, and this Agreement shall continue in effect with respect to the natural gas so delivered by Shipper. 9.3. Removal of General Partner. In the event that the General Partner is removed as general partner of Gatherer pursuant to Section 11.2 of the Partnership Agreement under circumstances where cause (as such term is defined in Section 1.1 of the Partnership Agreement) for such removal does not exist and the General Partner does not consent to that removal, then Shipper and Affiliates shall have no obligation under this Agreement with respect to wells drilled by Shipper on or after the effective date of such removal. 9 Article 10. FORCE MAJEURE 10.1. Non-Performance. No failure or delay in performance, whether in whole or in part, by either Gatherer or Shipper shall be deemed to be a breach hereof (other than the obligation to pay amounts when due under this Agreement) when such failure or delay is occasioned by or due to a Force Majeure Event. 10.2. Force Majeure Notice. The party affected by a Force Majeure Event shall give notice to the other party as soon as reasonably possible of the Force Majeure Event and the expected duration of the Force Majeure Event. 10.3. Remedy of a Force Majeure Notice. The affected party will use all reasonable efforts to remedy each Force Majeure Event and resume full performance under this Agreement as soon as reasonably practicable, except that the settlement of strikes, lockouts or other labor disputes shall be entirely within the discretion of the affected party. Article 11. GOVERNMENTAL RULES AND REGULATIONS This Agreement and all operations hereunder shall be subject to all valid laws, orders, directives, rules, and regulations of any governmental body, agency, or official having jurisdiction in the premises, whether state or federal. Notwithstanding any other provisions in this Agreement, in the event the Federal Energy Regulatory Commission or other governmental authority imposes a rule, regulation, order, law or statute which directly or indirectly materially and adversely affects a party's ability to perform its obligations under this Agreement, then the party so affected may terminate this Agreement as to the wells or portions of the Gathering System affected thereby by giving ten (10) days prior written notice to the other parties. Article 12. INSURANCE Shipper and Gatherer shall procure and maintain the insurance coverage described in Exhibit E. Article 13. TAXES Shipper shall pay or cause to be paid all taxes and assessments imposed on Shipper hereunder with respect to Shipper's Gas gathered hereunder prior to and including its delivery to Gatherer. Shipper shall pay to Gatherer all taxes, levies or charges which Gatherer may be required to collect from Shipper by reason of all services performed for Shipper hereunder other than taxes or assessments with respect to Gatherer's income, capital, properties, franchises or similar matters relating solely to Gatherer's general business activities or partnership or corporate existence or those of any of its subsidiaries. Neither party shall be responsible or liable for any taxes or other statutory charges levied or assessed against any of the facilities of the other party used for the purposes of carrying out the provisions of this Agreement. 10 Article 14. MISCELLANEOUS 14.1. Choice of Law; Submission to Jurisdiction. This Agreement shall be subject to and governed by the laws of the Commonwealth of Pennsylvania, excluding any conflicts-of-law rule or principle that might refer the construction or interpretation of this Agreement to the laws of another state. Each party hereby submits to the jurisdiction of the state and federal courts in the Commonwealth of Pennsylvania and to venue, respectively, in Philadelphia, Pennsylvania and the Eastern District of Pennsylvania. 14.2. Notice. All notices or requests or consents provided for or permitted to be given pursuant to this Agreement must be in writing and must be given by depositing same in the United States mail, addressed to the party to be notified, postpaid, and registered or certified with return receipt requested or by delivering such notice in person or by telecopier to such party. Notice given by personal delivery or mail shall be effective upon actual receipt. Notice given by telecopier shall be effective upon actual receipt if received during the recipient's normal business hours, or at the beginning of the recipient's next business day after receipt if not received during the recipient's normal business hours. All notices to be sent to a party pursuant to this Agreement shall be sent to 311 Rouser Road, P.O. Box 611, Moon Township, Pennsylvania 15108, Facsimile: (412) 262-2820, Attention: Tony C. Banks at such other address as such party may stipulate to the other parties in the manner provided in this Section. 14.3. Entire Agreement. This Agreement constitutes the entire agreement of the parties relating to the matters contained herein, superseding the provisions of all other contracts or agreements, whether oral or written, that are in conflict with the provisions hereof. 14.4. Effect of Waiver or Consent. No waiver or consent, express or implied, by any party to or of any breach or default by any party in the performance by such party of its obligations hereunder shall be deemed or construed to be a consent or waiver to or of any other breach or default in the performance by such Person of the same or any other obligations of such Person hereunder. Failure on the part of a party to complain of any act of any Person or to declare any Person in default, irrespective of how long such failure continues, shall not constitute a waiver by such party of its rights hereunder until the applicable statute of limitations period has run. 14.5. Amendment or Modification. This Agreement may be amended or modified from time to time only by the written agreement of all the parties hereto; provided, however, that Gatherer may not, without the prior approval of the conflicts committee of the General Partner, agree to any amendment or modification of this Agreement that, in the reasonable discretion of the General Partner, will adversely affect the Common Unit holders. 11 14.6. Assignment. No party shall have the right to assign its rights or obligations under this Agreement without the consent of the other parties hereto. 14.7. Counterparts. This Agreement may be executed in any number of counterparts with the same effect as if all signatory parties had signed the same document. All counterparts shall be construed together and shall constitute one and the same instrument. 14.8. Severability. If any provision of this Agreement or the application thereof to any Person or circumstance is determined by a court of competent jurisdiction to be invalid, void or unenforceable, the remaining provisions hereof, or the application of such provision to Persons or circumstances other than those as to which it has been held invalid or unenforceable, shall remain in full force and effect and shall in no way be affected, impaired or invalidated thereby, so long as the economic or legal substance of the transactions contemplated hereby is not affected in any manner materially adverse to any party. Upon such determination, the parties shall negotiate in good faith in an effort to agree upon a suitable and equitable substitute provision to effect the original intent of the parties. 14.9. Further Assurances. In connection with this Agreement and all transactions contemplated by this Agreement, each signatory party hereto agrees to execute and deliver such additional documents and instruments and to perform such additional acts as may be necessary or appropriate to effectuate, carry out and perform all of the terms, provisions and conditions of this Agreement and all such transactions. 14.10. Third Party Beneficiaries. The provisions of this Agreement are enforceable solely by the parties to it, and no Common Unit holder or its assignee or any other Person shall have the right, separate and apart from Gatherer, to enforce any provision of this Agreement or to compel any party to this Agreement to comply with its terms. 14.11. Headings. The headings throughout this Agreement are inserted for reference purposes only, and are not to be construed or taken into account in interpreting the terms and provisions of any Article, nor to be deemed in any way to qualify, modify or explain the effects of any such term or provision. 12 IN WITNESS WHEREOF, the parties have executed this Agreement to be effective as of the date first written above. Shipper: ATLAS AMERICA, INC. By:______________________________________ Name:____________________________________ Its:_____________________________________ RESOURCE ENERGY, INC. By:______________________________________ Name:____________________________________ Its:_____________________________________ VIKING RESOURCES CORPORATION By:______________________________________ Name:____________________________________ Its:_____________________________________ Gatherer: ATLAS PIPELINE OPERATING PARTNERSHIP, L.P. By: Atlas Pipeline Partners GP, LLC, its general partner By:______________________________________ Name:____________________________________ Its:_____________________________________ ATLAS PIPELINE PARTNERS, L.P. By: Atlas Pipeline Partners GP, LLC, its general partner By:______________________________________ Name:____________________________________ Its:_____________________________________ 13 EXHIBIT A GATHERING SYSTEM DESCRIPTION EXHIBIT B SHIPPER'S EXISTING WELL INTERESTS EXHIBIT C EXISTING THIRD PARTY WELL INTERESTS EXHIBIT D-1 DELIVERY POINTS EXHIBIT D-2 RECEIPT POINTS EXHIBIT E INSURANCE REQUIREMENTS EX-10 13 ex-10f.txt EXHIBIT 10(F) EXHIBIT 10(f) OMNIBUS AGREEMENT DATED FEBRUARY 2, 2000 AMONG ATLAS AMERICA, INC., RESOURCE ENERGY, INC., AND VIKING RESOURCES CORPORATION, AND ATLAS PIPELINE OPERATING PARTNERSHIP, L.P., AND ATLAS PIPELINE PARTNERS, L.P. OMNIBUS AGREEMENT THIS OMNIBUS AGREEMENT is made as of February 2, 2000 among ATLAS AMERICA, INC., a Delaware corporation ("Atlas America"), RESOURCE ENERGY, INC., a Delaware corporation ("Resource Energy"), and VIKING RESOURCES CORPORATION, a Pennsylvania corporation (collectively with Atlas America and Resource Energy, the "Resource Entities"), and ATLAS PIPELINE OPERATING PARTNERSHIP, L.P., a Delaware limited partnership, and ATLAS PIPELINE PARTNERS, L.P., a Delaware limited partnership (collectively, the "MLP"). R E C I T A L S: A. The MLP has acquired from the Resource Entities and their Affiliates (as such term in hereafter defined) natural gas gathering systems and related facilities consisting of approximately 888 miles of intrastate pipelines located in New York, Ohio and Pennsylvania. B. The Resource Entities have sponsored in the past, and intend to sponsor in the future, oil and gas drilling programs in areas served by the MLP's gathering systems. In connection with the transfer of the gathering systems to the MLP, the Resource Entities have undertaken to enter into arrangements with the MLP regarding adding wells to the MLP gathering system (Article 2), providing consultation services to the MLP in the construction of additions or extensions to the gathering systems (Article 3), providing certain funds to the MLP for construction (Article 4) and disposing of their ownership interests in the general partners of investment programs and of the MLP (Article 5). NOW, THEREFORE, in consideration of the premises and the covenants, conditions, and agreements contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties, intending to be legally bound hereby, agree as follows: ARTICLE 1. DEFINITIONS Unless otherwise defined in this Agreement, the following terms shall have the following meanings: "Affiliate" means, with respect to any Person, any other Person that, directly or indirectly, through one or more intermediaries, controls, is controlled by or is under common control with the Person in question. As used herein, the term "control" means (i) direct or indirect beneficial ownership of 50% or more of the voting securities or voting interest of a Person or, in the case of a limited partnership, of 50% or more of the general partnership interest, either directly or through an entity which the Person controls or (ii) the possession of the power to direct the management of a Person, whether through contract or otherwise. For the purposes of this Agreement, each Investment Program shall be deemed to be an Affiliate of the appropriate Resource Entity. "Agreement" means this Omnibus Agreement, as it may be amended, modified or supplemented from time to time. "Applicable Period" means the period commencing on the date hereof and ending on the date on which the General Partner ceases to be the General Partner of the MLP. "Common Units" means common units of limited partnership interest of Atlas Pipeline Partners, L.P. "Connectable Well" means a Resource Entity Well that is drilled within 2,500 feet of the Gathering System, such distance to be measured from the outside edge of the wellhead of the Resource Entity Well to the nearest point of intersection with the Gathering System. "Flow Line" means small diameter (two inches or less) sales or flow line from a wellhead, or such other type of line as may connect a well to a gathering system in accordance with standard industry practice. "Gathering System" means the natural gas pipelines and related facilities now owned or hereafter acquired by the MLP. "General Partner" means Atlas Pipeline Partners GP, LLC, a Delaware limited liability company. "Identified Third Party Gathering System" has the meaning set forth in Section 2.5. "Investment Program" means a Person for whom a Resource Entity or a subsidiary of a Resource Entity acts as a general partner, managing partner or manager (each, a "Manager") and the securities of which have been offered and sold to investors. "Master Natural Gas Gathering Agreement" means the Master Natural Gas Gathering Agreement among the Resource Entities and the MLP of even date herewith. "Other Delivery Point" means a delivery point other than the Gathering System. "Partnership Agreement" means the First Amended and Restated Agreement of Limited Partnership of Atlas Pipeline Partners, L.P. of even date herewith. "Person" means an individual, corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association or other entity. "Resource Entity Well" means any natural gas well both drilled and operated by a Resource Entity for itself or for an Affiliate. "Third Party Gathering System" means a natural gas gathering system owned by a Person other than the MLP or a subsidiary of the MLP. "Transfer" means a sale of all or substantially all of the assets of a Person, the disposition of more than 50% of the capital stock (or partnership or membership interests) of a Person or a merger or consolidation that results in a Resource Entity's owning, directly or indirectly, less than 50% of a Person's capital stock (or partnership or membership interests), but shall exclude transfers or pledges of assets or capital stock (or partnership or membership interests) of a Person to a financial institution or other lender in connection with a secured funding arrangement. 2 ARTICLE 2. CONNECTIONS TO RESOURCE ENTITY WELLS 2.1. Construction of Flow Lines from Connectable Wells. The Resource Entities jointly and severally agree that, at their sole cost and expense, they will construct up to 2,500 feet of Flow Line from any Connectable Well to the Gathering System. Such Flow Lines shall be the property of the owner of the relevant Resource Entity Well. 2.2. Drilling New Wells. On or before December 31, 2002, the Resource Entities agree to drill, on behalf of themselves or their Affiliates, in the aggregate at least 225 Connectable Wells, which number shall include those Connectable Wells drilled by any Investment Program during 1999. 2.3. Construction of Flow Lines from Other Resource Entity Wells. 2.3.1. Resource Entities' Right to Require Extension of the Gathering System. With respect to Resource Entity Wells other than Connectable Wells, if a Resource Entity constructs a Flow Line from any such Resource Entity Well to within 1,000 feet of the Gathering System (such distance to be measured from the end of the related Flow Line from the Resource Entity Well to the nearest point of intersection with the Gathering System), the Resource Entities shall be entitled to require the MLP, at the MLP's sole cost and expense, to extend the Gathering System to meet such Flow Line. The Resource Entities shall give the MLP written notice of the intent to drill a Resource Entity Well subject to this Section. Within 30 days of the date of the Resource Entities' notice, the MLP shall advise the Resource Entities whether it wishes to exercise its rights under this Section. If the MLP exercises its rights under this Section, the Resource Entities shall complete construction of the Gathering System extension within 60 days after the date designated by the Resource Entities as the date the Resource Entity Well will be completed as a producing natural gas well. 2.3.2. MLP's Right to Extend the Gathering System. With respect to Resource Entity Wells other than Connectable Wells and those described in Section 2.3.1, the MLP shall have the right, at its sole cost and expense, to extend the Gathering System to within 2,500 feet of any Resource Entity Well and to require the Resource Entities to construct, at the Resource Entities' sole cost and expense, up to 2,500 feet of Flow Line from the Resource Entity Well to the Gathering System extension (such distance to be measured from the end of the Flow Line from the Resource Entity Well to the nearest point of intersection with the Gathering System). The Resource Entities shall give the MLP written notice of the intent to drill a Resource Entity Well subject to this Section. Within 30 days of the date of the Resource Entities' notice, the MLP shall advise the Resource Entities in writing whether the MLP wishes to exercise its rights under this Section. If the MLP exercises its rights under this Section, it shall complete construction of the Gathering System extension within 60 days after the date designated by the Resource Entities as the date the Resource Entity Well will be completed as a producing natural gas well. 3 2.3.3. Connections with Other Delivery Points and Third Party Gathering Systems. In the event the MLP does not exercise its rights under Section 2.3.2, the Resource Entities may: (i) connect the Resource Entity Well to an Other Delivery Point, in which event the MLP shall be entitled to assume the costs of constructing the connecting Flow Line. If the MLP elects to assume such costs, it shall pay such costs to the Resource Entities within 30 days of receipt of Resource Entities' invoice therefor and the Flow Line shall be the property of the MLP and part of the Gathering System; or (ii) connect the Resource Entity Well to a Third Party Gathering System, in which event the MLP shall be entitled to assume the costs of constructing the connecting Flow Line. If the MLP elects to assume such costs, it shall pay such costs to the Resource Entities within 30 days of receipt of the invoice therefor and the Flow Line shall be the property of the MLP and part of the Gathering System. In addition, the Resource Entities shall pay to the MLP fees as required under Section 7.4 of the Master Natural Gas Gathering Agreement. 2.4. Well Connections. All well connections to Resource Entity Wells shall be at the direction of and in accordance with instructions and requirements of the MLP consistent with other wells connected to the Gathering System. Any such well shall be required to adhere to all of the operating, safety, pressure, and measurement provisions contained in the Master Natural Gas Gathering Agreement. 2.5. Consulting Services in Connection with Acquisitions. The Resource Entities agree to assist the MLP in seeking to identify for possible acquisition Third Party Gathering Systems and to provide consulting services to MLP in evaluating and acquiring any such identified gathering system. Further, the Resource Entities agree to give the MLP written notice of the identification by any of them of any Third Party Gathering System for possible acquisition by such Resource Entity or any Affiliate (each, an "Identified Third Party Gathering System"). Such notice shall identify the gathering system and its seller and the proposed sales price of the Identified Third Party Gathering System, and shall include all written information about the Identified Third Party Gathering System provided to the Resource Entities by or on behalf of the seller as well as any information or analyses compiled by the Resource Entities from other sources. Within 30 days of the date of the Resource Entities' notice, the MLP shall advise the Resource Entities in writing whether MLP wishes to acquire the Identified Third Party Gathering System. If the MLP advises the Resource Entities of its intent to acquire the Identified Third Party Gathering System, the Resource Entities shall refrain from making an offer for the Identified Third Party Gathering System except as permitted hereunder. If the MLP (i) advises the Resource Entities that it does not intend to acquire the Identified Third Party Gathering System, (ii) advises the Resource Entities of its intent to acquire the Identified Third Party Gathering System but does not complete the acquisition within 60 days of the MLP's notice of its intent to the Resource Entities or (iii) fails to timely advise the Resource Entities of its intent, any of the Resource Entities shall be free to acquire the Identified Third Party Gathering System. 4 ARTICLE 3. CONSTRUCTION MANAGEMENT SERVICES 3.1. Services to be Provided. In the event the MLP expands the Gathering System or constructs a new addition to the Gathering System, whether pursuant to Article 2 or otherwise, the Resource Entities agree to provide to the MLP construction management services in connection with any such expansion as requested by the MLP. In providing construction management services hereunder, the Resource Entities shall provide the services of a general contractor with respect to the applicable construction project. 3.2. Construction Contract. For each such construction project, the MLP and the relevant Resource Entity shall enter into a construction contract based substantially on the most current versions of AIA Document A111 (Standard Form of Agreement Between Owner and Contractor) and AIA Document A201 (General Conditions of the Contract for Construction), provided that the basis of payment shall be the cost of the work (including an allocable portion of the Resource Entity's employee salaries and benefits) and the MLP shall not be required to employ an architect. The Resource Entities shall not be entitled to any other compensation for the performance of construction management services hereunder. ARTICLE 4. STAND-BY FINANCING COMMITMENT 4.1. Financing Commitment. For the period commencing on the date hereof and ending on the fifth anniversary hereof, Atlas America and Resource Energy agree to provide to the MLP funding of up to an aggregate of One Million Five Hundred Thousand Dollars ($1,500,000) per annum to finance the cost of expanding the Gathering System or constructing new additions to the Gathering System. Atlas America and Resource Energy, jointly and severally, commit to provide such funding, upon the MLP's written request therefor, by purchasing Common Units at a price equal to the arithmetic average of the closing prices of the Common Units on the American Stock Exchange, or, if the American Stock Exchange is not the principal trading market for such security, on the principal trading market for such security, for the twenty consecutive trading days ending on the trading day prior to the purchase, or, if the fair market value of the Common Units cannot be calculated for such period on any of the foregoing bases, the average fair market value during such period as reasonably determined in good faith by the members of the managing board of the General Partner. 4.2. Procedures. The MLP shall give Atlas America and Resource Energy written notice of its intent to exercise its rights under Section 4.1. Thereafter, Common Units shall be issued to the appropriate Resource Entity, against delivery of the purchase price therefor in immediately available funds, within five business days of the date of each construction invoice issued by the Resource Entity to the MLP pursuant to Article 3. Each Common Unit so issued shall, upon receipt of payment therefor and issuance, be duly authorized, validly issued and fully paid. 4.3. Prohibited Uses. The MLP agrees to use the funds it obtains pursuant to this Article 4 for the purposes of financing initial construction costs only and further agrees that it will not request or use such funds for any other purpose, including capital improvements or maintenance to existing pipeline. 5 ARTICLE 5. THE GENERAL PARTNER 5.1. New Investment Programs. Until the earlier of the expiration of the Applicable Period or the closing of the Transfers described in the first sentence of Section 5.2, the Resource Entities agree that they shall cause a Manager of one of the Investment Programs currently existing to be designated as the Manager for Investment Programs organized after the date hereof and that the wells of Investment Programs organized after the date hereof shall be deemed to be Future Investment Program Well Interests for the purposes of the Master Natural Gas Gathering Agreement. 5.2. Disposition of Interest in the General Partner. The Resource Entities agree that they will not Transfer to any Person their ownership interest in the General Partner unless they simultaneously (i) Transfer to the same Person their ownership interest in the Manager of each of the Investment Programs and (ii) cause their Affiliates having an ownership interest in the General Partner or any Manager of an Investment Program to Transfer such interest to the same Person. The provisions of this Section shall not apply to a Transfer to a wholly- or majority-owned direct or indirect subsidiary or parent of any of the Resource Entities so long as the Resource Entities' or their parent continue to control the relevant general partner. ARTICLE 6. TERMINATION This Agreement shall terminate, and no party shall have any further obligation hereunder, in the event that the General Partner is removed as general partner of the MLP pursuant to Section 11.2 of the Partnership Agreement under circumstances where cause (as such term is defined in Section 1.1 of the Partnership Agreement) for such removal does not exist and the General Partner does not consent to that removal. ARTICLE 7. MISCELLANEOUS 7.1. Choice of Law; Submission to Jurisdiction. This Agreement shall be subject to and governed by the laws of the Commonwealth of Pennsylvania, excluding any conflicts-of-law rule or principle that might refer the construction or interpretation of this Agreement to the laws of another state. Each party hereby submits to the jurisdiction of the state and federal courts in the Commonwealth of Pennsylvania and to venue in, respectively, Philadelphia, Pennsylvania and the Eastern District of Pennsylvania. 7.2. Notice. All notices or requests or consents provided for or permitted to be given pursuant to this Agreement must be in writing and must be given by depositing same in the United States mail, addressed to the party to be notified, postpaid, and registered or certified with return receipt requested or by delivering such notice in person or by telecopier to such party. Notice given by personal delivery or mail shall be effective upon actual receipt. Notice given by telecopier shall be effective upon actual receipt if received during the recipient's normal business hours, or at the beginning of the recipient's next business day after receipt if not received during the recipient?s normal business hours. All notices to be sent to a party pursuant to this Agreement shall be sent to 311 Rouser Road, P.O. Box 611, Moon Township, PA 15108, Facsimile: (412) 262-2820, Attention: Tony C. Banks or at such other address as such party may stipulate to the other parties in the manner provided in this Section. 7.3. Entire Agreement. This Agreement constitutes the entire agreement of the parties relating to the matters contained herein, superseding all other contracts or agreements, whether oral or written, that are in conflict with the provisions hereof. 6 7.4. Effect of Waiver or Consent. No waiver or consent, express or implied, by any party to or of any breach or default by any party in the performance by such party of its obligations hereunder shall be deemed or construed to be a consent or waiver to or of any other breach or default in the performance by such Person of the same or any other obligations of such Person hereunder. Failure on the part of a party to complain of any act of any Person or to declare any Person in default, irrespective of how long such failure continues, shall not constitute a waiver by such party of its rights hereunder until the applicable statute of limitations period has run. 7.5. Amendment or Modification. This Agreement may be amended or modified from time to time only by the written agreement of all the parties hereto; provided, however, that the MLP may not, without the prior approval of the conflicts committee of the General Partner, agree to any amendment or modification of this Agreement that, in the reasonable discretion of the General Partner, will adversely affect the Common Unit holders. 7.6. Assignment. No party shall have the right to assign its rights or obligations under this Agreement without the consent of the other parties hereto. 7.7. Counterparts. This Agreement may be executed in any number of counterparts with the same effect as if all signatory parties had signed the same document. All counterparts shall be construed together and shall constitute one and the same instrument. 7.8. Severability. If any provision of this Agreement or the application thereof to any Person or circumstance is determined by a court of competent jurisdiction to be invalid, void or unenforceable, the remaining provisions hereof, or the application of such provision to Persons or circumstances other than those as to which it has been held invalid or unenforceable, shall remain in full force and effect and shall in no way be affected, impaired or invalidated thereby, so long as the economic or legal substance of the transactions contemplated hereby is not affected in any manner materially adverse to any party. Upon such determination, the parties shall negotiate in good faith in an effort to agree upon a suitable and equitable substitute provision to effect the original intent of the parties. 7.9. Further Assurances. In connection with this Agreement and all transactions contemplated by this Agreement, each signatory party hereto agrees to execute and deliver such additional documents and instruments and to perform such additional acts as may be necessary or appropriate to effectuate, carry out and perform all of the terms, provisions and conditions of this Agreement and all such transactions. 7.10. Third Party Beneficiaries. The provisions of this Agreement are enforceable solely by the parties to it, and no Common Unit holder or its assignee or any other Person shall have the right, separate and apart from the MLP, to enforce any provision of this Agreement or to compel any party to this Agreement to comply with its terms. 7.11. Headings. The headings throughout this Agreement are inserted for reference purposes only, and are not to be construed or taken into account in interpreting the terms and provisions of any Article, nor to be deemed in any way to qualify, modify or explain the effects of any such term or provision. 7 IN WITNESS WHEREOF, the parties have executed this Agreement on, and effective as of, the date first written above. THE MLP: ATLAS PIPELINE OPERATING PARTNERSHIP, L.P. By: Atlas Pipeline Partners GP, LLC Its general partner By: -------------------------------------- Name: -------------------------------------- Its: -------------------------------------- ATLAS PIPELINE PARTNERS, L.P. By: Atlas Pipeline Partners GP, LLC Its general partner By: -------------------------------------- Name: -------------------------------------- Its: -------------------------------------- THE RESOURCE ENTITIES: ATLAS AMERICA, INC. By: -------------------------------------- Name: -------------------------------------- Its: -------------------------------------- RESOURCE ENERGY, INC. By: -------------------------------------- Name: -------------------------------------- Its: -------------------------------------- VIKING RESOURCES CORPORATION By: -------------------------------------- Name: -------------------------------------- Its: -------------------------------------- EX-10 14 ex-10g.txt EXHIBIT 10(G) EXHIBIT 10(g) NATURAL GAS GATHERING AGREEMENT DATED JANUARY 1, 2002 AMONG ATLAS PIPELINE PARTNERS, L.P., AND ATLAS PIPELINE OPERATING PARTNERSHIP, L.P. AND ATLAS RESOURCES, INC., AND ATLAS ENERGY GROUP, INC. AND ATLAS NOBLE CORPORATION, AND RESOURCE ENERGY INC., AND VIKING RESOURCES CORPORATION NATURAL GAS GATHERING AGREEMENT THIS NATURAL GAS GATHERING AGREEMENT is made as of the 1st day of January 2002 among: ATLAS PIPELINE PARTNERS, L.P., a Delaware limited partnership, and ATLAS PIPELINE OPERATING PARTNERSHIP, L.P., a Delaware limited partnership (hereinafter referred to collectively as Gatherer) and ATLAS RESOURCES, INC., a Pennsylvania corporation, and ATLAS ENERGY GROUP, INC., an Ohio Corporation, and ATLAS NOBLE CORPORATION, a Delaware Corporation, and RESOURCE ENERGY INC., a Delaware Corporation, and VIKING RESOURCES CORPORATION, a Pennsylvania Corporation (hereinafter referred to collectively as Shipper). Recitals: A. Gatherer owns a natural gas gathering system and related facilities located in New York, Ohio and Pennsylvania, and operated as a private use gathering system ("Gathering System"). B. Shipper has recently entered into gas purchase agreements with non-affiliated parties and has arranged for the connection of their production to the Gathering System, said parties and production which are more particularly described in Exhibit A (" Third Party Production Sources"). C. Gatherer and Shipper desire to provide for the gathering and redelivery of the gas produced from these Third Party Production Sources ("Shipper's Gas"), as more fully provided herein. NOW, THEREFORE, in consideration of the premises, and the mutual covenants and agreements herein set forth, and intending to be legally bound, the parties agree as follows: Article I. DEFINITIONS Unless otherwise defined herein, the following terms shall have the following meanings: "Agreement" means this Natural Gas Gathering Agreement, as it may be amended, modified or supplemented from time to time. "Day" means a period of time beginning at 7:00 a.m., Eastern Time, on each calendar day and ending at 7:00 a.m., Eastern Time, on the next succeeding calendar day. "Delivery Points" means those points of interconnect with various local distribution companies, interstate pipelines, and end-users located on the Gathering System where Shipper's Gas can be redelivered by Gatherer. "Force Majeure Event " means any act of God, strike, lockout, or other industrial disturbance, act of a public enemy, sabotage, war (whether or not an actual declaration is made thereof), blockade, insurrection, riot, epidemic, landslide, lightning, earthquake, flood, storm, fire, washout, arrest and restraint of rules and peoples, civil disturbance, explosion, breakage or accident to machinery or line or pipe, hydrate obstruction of line or pipe, lack of pipeline capacity, repair, maintenance, improvement, replacement, or alteration to plant or line of pipe or related facility, failure or delay in transportation, temporary failure of gas supply or markets, freezing of the well or delivery facility, well blowout, cratering, partial or entire failure of the gas well, the act of any court, agency or governmental authority, or any other cause, whether of the kind enumerated or otherwise, not within the reasonable control of the party claiming suspension. "General Partner" means Atlas Pipeline Partners GP, LLC, a Delaware limited liability company. "Gross Sale Price " shall mean the price, per mcf, actually received by Shipper for natural gas sold by it. "mcf" means one thousand (1,000) cubic feet of gas measured at a base temperature of sixty degrees (60(degree)) Fahrenheit and at a pressure base of fourteen and seventy-three one-hundredths (14.73) psla. "mmcf" means one million (1,000,000) cubic feet of gas measured at a base temperature of sixty degrees (60(degree)) Fahrenheit and at a pressure base of fourteen and seventy-three one-hundredths (14.73) psia. "Person " means an individual, corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association or other entity. "psia" means pounds per square inch absolute. "psig" means pounds per square inch gauge. "Receipt Points" means the points on the Gathering System described in Exhibit A where gas produced from the Third Party Production Sources is delivered into the Gathering System. "Shipper's Field Fuel" means Shipper's allocated share of actual Gathering System fuel requirements, shrinkage, and lost and unaccounted for gas. Such allocations shall be based upon the proportion volume of natural gas that Shipper's Gas bears to the aggregate gathered by Gatherer during the relevant period. Article 2. GATHERING SERVICES 2.1. Receipt of Gas. Subject to the terms, limitations, and conditions of this Agreement, Shipper agrees to deliver to the Receipt Points on a best-efforts basis, and Gatherer agrees to accept at the Receipt Points, on a fully interruptible basis, all those volumes of gas made available to Shipper from the Third Party Production Sources; provided, however, that Gatherer shall only be obligated to accept on any Day for gathering hereunder that volume of Shipper's Gas which Gatherer determines, in its sole discretion, it has available capacity to receive. 2.2. Redelivery of Gas. Gatherer will gather, compress, and redeliver, on a an interruptible basis, to the Delivery Points, and Shipper will accept at the Deliver Points, a quantity of gas equal, on an mcf basis, to the quantity of Shipper's Gas received at the Receipt Points less Shipper's Field Fuel. 2.3. Shipper Is Field Fuel. Shipper's Field Fuel will be calculated monthly by Gatherer by allocating such quantities of actual Gathering System fuel requirements, shrinkage, and lost and unaccounted for gas between all shippers using the Gathering System. Gatherer may retain and use Shipper's Field Fuel as fuel for compression and other operations on the Gathering System. 2.4. Commingling Shipper Is Gas. Gatherer shall have the right to commingle Shipper's Gas with other natural gas in the Gathering System. Gatherer may extract, or permit to be extracted, from Shipper's Gas condensate to the extent necessary to meet the quality requirements of the receiving pipeline at the Delivery Points or for proper functioning of the Gathering System. Article 3. TITLE AND LIABILITY 3.1. Shipper's Gas. Except for Shipper's Field Fuel and products removed in treating Shipper's Gas, title to Shipper's Gas shall remain with Shipper. 3.2. Adverse Claims. Shipper shall indemnify, hold harmless and defend Gatherer, the General Partner and the officers, agents, employees and contractors of Gatherer and the General Partner (each, an "Indemnified Person") against any liability, loss or damage whatsoever, including costs and attorneys fees (collectively, a "Loss"), suffered by an Indemnified Person, where such Loss arises, directly or indirectly, out of any demand, claim, action, cause of action or suit brought by any Person asserting ownership of or an interest in Shipper's Gas. 3.3. Possession and Control. As between the parties hereto, Gatherer shall be deemed to be in control and possession of Shipper's Gas after Gatherer receives Shipper's Gas at any Receipt Point and until Shipper's Gas is delivered at any Delivery Point; provided, however, that Gatherer shall not, by any such possession and control, be deemed to have title to Shipper's Gas it receives. Shipper shall be deemed to be in control and possession of Shipper's Gas at all other times. 3.4. Indemnity. The party deemed to be in control and possession of Shipper's Gas shall be responsible for and shall indemnify the other party with respect to any Losses arising in connection with or related to Shipper's Gas when it is in the indemnifying party's control and possession; provided, that no party shall be responsible for any Losses arising from the other party's negligence or breach of this agreement. Article 4. DELIVERY PRESSURE 4.1. Receipt Points. Shipper shall, on a best efforts basis, deliver Shipper's Gas at a pressure sufficient to effect delivery into the Gathering System at the Receipt Points, but not in excess of the maximum pressure specified by Gatherer from time to time. Shipper shall not be required to install compression to effectuate deliveries into the Gathering System. 4.2. Compression. Gatherer shall maintain all existing compression facilities, unless Shipper shall otherwise consent in writing, and shall install such additional compression facilities as may be necessary or appropriate under good industry practices and commercially reasonable. 4.3. Wellhead Equipment. Shipper shall install or cause to be installed, and shall operate and maintain, at its sole expense, all wellhead and pressure regulating equipment necessary to prevent Shipper's delivery pressure at the Receipt Point from exceeding the maximum pressure specified by Gatherer from time to time. 4.4. Inspection. Gatherer shall have the right at any time, but not the obligation, to inspect Shipper's facilities at the Receipt Points, and Gatherer may immediately cease accepting Shipper's Gas if the pressure in Shipper's facilities exceeds the maximum pressure reasonably established by Gatherer from time to time, or require Shipper to install equipment necessary to limit the pressure to such maximum. Article 5. GAS QUALITY 5.1. Minimum Specifications. Shipper's Gas delivered into the Gathering System shall be commercially free from liquids of any kind, air, dust, gum, gum forming constituents, harmful or noxious vapors, or other solid or liquid matter which, in the sole judgment of Gatherer, may interfere with the merchantability of Shipper's Gas or cause injury to or interfere with proper operation of the lines, regulators, meters or other equipment of the Gathering System. Shipper's Gas shall also conform to applicable quality specifications of the receiving pipeline at each applicable Delivery Point. 5.2. Suspension. Gatherer may, at its option, (i) refuse to accept delivery of any Shipper's Gas not meeting the above-described quality specifications, or (ii) accept delivery of all or any part of Shipper's Gas (notwithstanding the deficiency in quality). Shipper shall be responsible for all damages to the Gathering System, including costs of repair, due to its failure to comply with such quality specifications. Article 6. MEASUREMENT AND TESTING 6.1. Measurement Equipment. Measurement of Shipper's Gas shall take place at the Receipt. Points. Shipper will install, or cause to be installed, at or near the Receipt Points, orifice meters or other measuring equipment necessary in Gatherer's judgment to accurately measure the volumes of Shipper's Gas being delivered into the Gathering System to the extent such meters or other measuring equipment have not been installed as of the date of this Agreement. Such measuring equipment shall be comparable to the measuring equipment of other parties delivering gas into the Gathering System. Shipper shall be responsible for, and bear the cost of, acquiring, installing, maintaining and operating such measurement equipment. 6.2. Chart Integration. Gatherer shall be responsible for reading the meters at the Receipt Points. Gatherer shall furnish, install, remove, and integrate all recording charts used in such meters in accordance with Gatherer's standard practices. 6.3. Delivery Points. The measurement of and tests for quality of Shipper's Gas redelivered at the Delivery Points shall be governed by and determined in accordance with the requirements of the receiving pipeline at each Delivery Point. 6.4. Unit of Volume. The unit of volume for purposes of measurement shall be one (1) cubic foot of gas at a temperature base of sixty degrees (600) Fahrenheit and at a pressure base of fourteen and seventy-three one-hundredths (14.73) psia. 6.5. Testing Procedures. Shipper shall follow the meter calibrations schedule established by Gatherer for each meter on the Gathering System. Such calibrations shall occur at least once every twelve (12) months but not more frequently than once every six (6) months. No testing, calibration, or adjustment of a meter or related equipment shall be performed without Gatherer first being given five (5) days' notice thereof and having the opportunity to be present. 6.6. Meter Inaccuracy. If, at any time, any meter is found to be out of service or registering inaccurately in any percentage, it shall be adjusted at once by Shipper to read accurately within the limits prescribed by the meter's manufacturer. If such equipment is out of service or inaccurate by an amount exceeding three percent (3%) of a reading corresponding to the average flow rate for the period since the last test, the previous readings shall be corrected for the period that the meter is known to be inaccurate, or, if not known, a period of one-half(Y2) the elapsed time since the last test. The volume of Shipper's Gas delivered during such period shall be estimated by Gatherer either (i) by using the data recorded by any check measuring equipment if installed and accurately registered, (ii) by correcting the error if the percentage of error is ascertainable by calibration, test, or mechanical calculation or, if neither such method is feasible, (iii) by estimating the quantity delivered based upon deliveries under similar conditions during a period when the equipment registered accurately. No volume correction shall be made for metering inaccuracies of three percent (3%) or less. 6.7. Meter Testing. If Gatherer requests to have any meter tested, then Shipper shall have the meter tested in the presence of and to the satisfaction of Gatherer. If the meter tested proves to be accurate within plus or minus three percent (3%) at its normal operating range, then the cost of testing and recalibrating the meter shall be borne by Gatherer. Shipper will schedule all required tests within ten (10) days of a request by Gatherer. Shipper will notify Gatherer at least five (5) working days prior to the test of the date, time, and location of such test. 6.8. Books and Records. Gatherer shall keep and maintain proper books of account during the term of this Agreement and for a period of three (3) years thereafter showing (a) the total volume of Shipper's Gas transported through the Gathering System from the Receipt Points to the Delivery Points and (b) the volume of gas allocated to each Receipt Point. Gatherer shall also preserve, or cause to be preserved, for at least one (1) year all test data, charts, and similar data pertaining to the measurement and testing of Shipper's Gas, unless a longer period is prescribed by applicable regulations. Shipper shall have the right during normal business hours, after reasonable notice to Gatherer, to inspect Gatherer's books and records not older than three (3) years from the date of request for inspection. Such inspections shall take place at Gatherer's office. Any costs attributable to such audits or inspections shall be borne by Shipper. Article 7. GATHERING FEES 7.1. Consideration. As consideration for gathering Shipper's Gas, Shipper shall pay to Gatherer those fees identified on Exhibit A for each of the Third Party Production Sources. Article 8. BILLING AND PAYMENT 8.1. Statements and Payments. In connection with fees payable to Gatherer under Article 7 of this Agreement, Gatherer shall prepare and submit to Shipper each month a statement showing for the prior month (i) the volume of Shipper's Gas received at the Receipt Points, (ii) Shipper's Field Fuel, and (iii) the volume of Shipper's Gas delivered to the Delivery Points. Shipper shall provide Gatherer, within ninety (90) days after the end of each month, a statement of the gathering fees due for such month. Shipper's statement shall set forth (i) the volumes of Shipper's Gas for which payments have been received, (ii) an itemization of the Gross Sale Price or Prices received for Shipper's Gas, if appropriate; and (iii) a calculation of the gathering fees for such Shipper's Gas. Shipper shall have the right to inspect Gatherer's books and records relating to such Shipper's Gas for purposes of verifying the accuracy of Gatherer's statement. Shipper shall advise Gatherer within 30 days of Shipper's receipt of Gatherer's statement if Shipper believes Gatherer's statement to be inaccurate in any respect. If Shipper does not so advise Gatherer, Gatherer's statement shall be deemed to be correct. The gathering fee shall be due and payable upon Shipper's receipt of Gatherer's statement and payment shall be made to Gatherer at the following address: Atlas Pipeline Partners 311 Rouser Road, P.O. Box 611 Moon Township, Pennsylvania 15108 Attn: Transportation Revenue Each of Gatherer and Shipper shall preserve its records relating to any statement delivered pursuant to this Section 8.1 for a period of at least three (3) years after such statement is delivered. 8.2. Payment Default. If Shipper fails to pay Gatherer in accordance with Section 8.1, Gatherer may, at its option and without limiting any other remedies, either, singularly or in combination, (i) terminate this Agreement forthwith and without notice or (ii) suspend performance under this Agreement until all indebtedness under this Agreement is paid in full. 8.3. Overdue Payments. Any overdue balance shall accrue daily interest charges at the rate equal to the lesser of (i) 15% per annum or (ii) the maximum lawful rate of interest. 8.4. Remittance of Revenues. If any revenues for sales of Shipper's Gas are paid directly to Gatherer, Gatherer shall remit such revenues to Shipper within fifteen (15) days; provided, however, that Gatherer may offset from any such revenues any amounts as shall then be due and payable to Gatherer under this Agreement. 8.5. Gathering Fees Payable to Shipper. Shipper shall have sole and exclusive responsibility for settling with all Persons having an interest in Shipper's Gas and collecting gathering fees payable to Shipper with respect thereto. Shipper's obligations hereunder shall be without regard to receipt or collection by Shipper of any such fees. Article 9. TERM 9.1. Term. This Agreement shall become effective immediately and shall remain in effect for so long as Shipper continues to purchase natural gas from any Third Party Production Source identified in Exhibit A or until either Shipper or Gatherer elects to terminate the same by ninety (90) advance written notice or until this Agreement is otherwise terminated as provided herein. Gatherer recognizes that Shipper's arrangements with the Third Party Production Sources may be discontinued at any time and relieves Shipper of any obligation to continue deliveries from any Third Party Source whose sales to Shipper have been terminated. 9.2. Uneconomic Operation. Notwithstanding anything contained herein to the contrary, if at any time Gatherer determines, in its sole discretion, that continued operation of all or any part of the Gathering System is not economically justified, Gatherer may cease receiving Shipper's Gas from the relevant part of the Gathering System and terminate this Agreement as to such part of the Gathering System (the "Terminated System") by giving at least ninety (90) days' notice to Shipper. Article 10. FORCE MAJEURE 10.1. Non-Performance. No failure or delay in performance, whether in whole or in part, by either Gatherer or Shipper shall be deemed to be a breach hereof (other than the obligation to pay amounts when due under this Agreement) when such failure or delay is occasioned by or due to a Force Majeure Event.. 10.2. Force Majeure Notice. The party affected by a Force Majeure Event shall give notice to the other party as soon as reasonably possible of the Force Majeure Event and the expected duration of the Force Majeure Event. 10.3. Remedy of a Force Majeure Notice. The affected party will use all reasonable efforts to remedy each Force Majeure Event and resume full performance under this Agreement as soon as reasonably practicable, except that the settlement of strikes, lockouts or other labor disputes shall be entirely within the discretion of the affected party. Article 11. GOVERNMENTAL RULES AND REGULATIONS 11.1 This Agreement and all operations hereunder shall be subject to all valid laws, orders, directives, rules, and regulations of any governmental body, agency, or official having jurisdiction in the premises, whether state or federal. Notwithstanding any other provisions in this Agreement, in the event the Federal Energy Regulatory Commission or other governmental authority imposes a rule, regulation, order, law or statute which directly or indirectly materially and adversely affects a party's ability to perform its obligations under this Agreement, then the party so affected may terminate this Agreement as to the wells or portions of the Gathering System affected thereby by giving ten (10) days prior written notice to the other parties. Article 12. TAXES 12.1 Shipper shall pay or cause to be paid all taxes and assessments imposed on Shipper hereunder with respect to Shipper's Gas gathered hereunder prior to and including its delivery to Gatherer. Shipper shall pay to Gatherer all taxes, levies or charges which Gatherer may be required to collect from Shipper by reason of all services performed for Shipper hereunder other than taxes or assessments with respect to Gatherer's income, capital, properties, franchises or similar matters relating solely to Gatherer's general business activities or partnership or corporate existence or those of any of its subsidiaries. Neither party shall be responsible or liable for any taxes or other statutory charges levied or assessed against any of the facilities of the other party used for the purposes of carrying out the provisions of this Agreement. Article 13. MISCELLANEOUS 13.1. Choice of Law,. Submission to Jurisdiction. This Agreement shall be subject to and governed by the laws of the Commonwealth of Pennsylvania, excluding any conflicts-of-law rule or principle that might refer the construction or interpretation of this Agreement to the laws of another state. Each party hereby submits to the jurisdiction of the state and federal courts in the Commonwealth of Pennsylvania and to venue, respectively, in Philadelphia, Pennsylvania and the Eastern District of Pennsylvania. 13.2. Notice. All notices or requests or consents provided for or permitted to be given pursuant to this Agreement must be in writing and must be given by depositing same in the United States mail, addressed to the party to be notified, postpaid, and registered or certified with return receipt requested or by delivering such notice in person or by telecopier to such party. Notice given by personal delivery or mail shall be effective upon actual receipt. Notice given by telecopier shall be effective upon actual receipt if received during the recipient's normal business hours, or at the beginning of the recipient's next business day after receipt if not received during the recipient's normal business hours. All notices to be sent to a party pursuant to this Agreement shall be sent to: Gatherer: Atlas Pipeline Partners 1845 Walnut Street Philadelphia, PA 19103 Attention: Michael L. Staines, President Telephone: (215) 546-5005 Facsimile: (215) 546-5388 Shipper: Atlas America 311 Rouser Road P.0. Box 611 Moon Twp., PA 15108 Attention: John A. Ranieri, Director, Energy Sales Telephone: (412) 262-2830 x126 Fax: (412) 262-3927 or at such other address as such party may stipulate to the other parties in the manner provided in this Section. 13.3. Entire Agreement. This Agreement constitutes the entire agreement of the parties relating to the matters contained herein, superseding the provisions of all other contracts or agreements, whether oral or written, that are in conflict with the provisions hereof. 13.4 Effect of Waiver or Consent. No waiver or consent, express or implied, by any party to or of any breach or default by any party in the performance by such party of its obligations hereunder shall be deemed or construed to be a consent or waiver to or of any other breach or default in the performance by such Person of the same or any other obligations of such Person hereunder. Failure on the part of a party to complain of any act of any Person or to declare any Person in default, irrespective of how long such failure continues, shall not constitute a waiver by such party of its rights hereunder until the applicable statute of limitations period has run. 13.5. Amendment or Modification. This Agreement may be amended or modified from time to time only by the written agreement of all the parties hereto. 13.6. Assignment. No party shall have the right to assign its rights or obligations under this Agreement without the consent of the other parties hereto. 13.7. Counterparts. This Agreement may be executed in any number of counterparts with the same effect as if all signatory parties had signed the same document. All counterparts shall be construed together and shall constitute one and the same instrument. 13.8. Severability. If any provision of this Agreement or the application thereof to any Person or circumstance is determined by a court of competent jurisdiction to be invalid, void or unenforceable, the remaining provisions hereof, or the application of such provision to Persons or circumstances other than those as to which it has been held invalid or unenforceable, shall remain in full force and effect and shall in no way be affected, impaired or invalidated thereby, so long as the- economic or legal substance of the transactions contemplated hereby is not affected in any manner materially adverse to any party. Upon such determination, the parties shall negotiate in good faith in an effort to agree upon a suitable and equitable substitute provision to effect the original intent of the parties. 13.9. Further Assurances. In connection with this Agreement and all transactions contemplated by this Agreement, each signatory party hereto agrees to execute and deliver such additional documents and instruments and to perform such additional acts as may be necessary or appropriate to effectuate, carry out and perform all of the terms, provisions and conditions of this Agreement and all such transactions. 13.10 Third Party Beneficiaries. The provisions of this Agreement are enforceable solely by the parties to it, and no other Person shall have the right, separate and apart from Gatherer, to enforce any provision of this Agreement or to compel any party to this Agreement to comply with its terms. 13.11. Headings. The headings throughout this Agreement are inserted for reference purposes only, and are not to be construed or taken into account in interpreting the terms and provisions of any Article, nor to be deemed in any way to qualify, modify or explain the effects of any such term or provision. IN WITNESS WHEREOF, the parties have executed this Agreement to be effective as of the date first written above. Shipper: Gatherer: ATLAS RESOURCES, INC. ATLAS PIPELINE OPERATING PARTNERSHIP, L.P. By: /s/ Jeffrey C. Simmons ------------------------- By: Atlas Pipeline Partners GP, LLC, Name: Jeffrey C. Simmons Its: Executive VP Operations By: /s/ Michael L. Staines --------------------------------------- Name: Michael L. Staines Its: Chief Operating Officer and Secretary ATLAS ENERGY GROUP, INC. ATLAS PIPELINE PARTNERS, L.P. By: Atlas Pipeline Partners GP, LLC, Its general partner By: /s/ Jeffrey C. Simmons By: /s/ Michael L. Staines ------------------------- ------------------------------------------ Name: Jeffrey C. Simmons Name: Michael L. Staines Its: VP Operations Its: Chief Operating Officer and Secretary ATLAS NOBLE CORPORATION By: /s/ Jeffrey C. Simmons ------------------------- Name: Jeffrey C. Simmons Its: Executive VP RESOURCE ENERGY INC. By: /s/ Jeffrey C. Simmons ------------------------- Name: Jeffrey C. Simmons Its: Executive VP VIKING RESOURCES CORPORATION By: /s/ Jeffrey C. Simmons ------------------------- Name: Jeffrey C. Simmons Its: VP Production
EXHIBIT A THIRD PARTY PRODUCTION SOURCES Attached to and made part of the Natural Gas Gathering Agreement dated January 1, 2002 among ATLAS PIPELINE PARTNERS, L.P. AND ATLAS PIPELINE OPERATING PARTNERSHIP, L.P. (collectively as Gatherer), and ATLAS RESOURCES, INC., ATLAS ENERGY GROUP, INC., ATLAS NOBLE CORPORATION, RESOURCE ENERGY INC., and VIKING RESOURCES CORPORATION (collectively as Shipper) PURCHASER SELLER WELLS Atlas Energy Group, Inc. AnnaRock Petroleum LLC Britt #1 and #2, Powel #2, Carr #1 and #2, Hamett #1, Draa-Wolford #1, GSA #1,2 and 3, Hunkus Units #1 and #2, Logan #4, Mack #1, Swartz-Thurber Unit #1 IBM Well #6330, Luttner #1 and #2 various Belknap #1 and #4 Resource Energy, Inc. Bands Company, Inc. Terleski #1 and #2 Viking Resources Corporation Belden & Blake Corporation Vrankovich Unit #1, Patrick Unit #1, Viking Resources Corporation Belknap Reiter Unit #1, Coombs Unit #1, Wooten #1 Atlas Energy Group, Inc. Cedar Valley Energy, Inc. Dubyak lfft Wells Atlas Energy Group, Inc. D & L Energy Aten, Holy Cross Orthodox Wells Ken Green Well Atlas Energy Group, Inc. D & L Energy Schondel #1 and #2 Atlas Resources, Inc. D & L Energy Vincent #1 Atlas Resources, Inc. Daniel Heath Jerry Moore Inc. #5826 Viking Resources Corporation David A. Waldron & Associates, Inc. Carutis #1 Resource Energy, Inc. Dorfman Production Company Daw Mitchell Unit #1, Harlan #1 and #2, Viking Resources Corporation Jerry Moore, Inc. Mitchell #1, Otto Unit #2 Atlas America, Inc. Nomew, Inc. Basham #3 Atlas Noble Corporation Petrox, Inc. Larrick #2 Resource Energy Inc. S & S Energy Corp. Atlas Noble Corporation Sound Energy Company, Inc.
[RESTUBBED TABLE] GATHERING TOWNSHIP, COUNTY RATE Vernon and Gustavus Twps., Trumball Co., OH $.25 per Mcf 10% weighted average sales price Fayette Co., PA $.22 per Mcf 10% weighted average sales price Champion and Warren Twps., Trumball Co., OH 10% weighted average sales price Brookfield Twp., Trumball Co., OH $.20 per Mcf Hubbard Twp., Trumball Co., OH $.20 per Mcf Springfield and Hermitage Twps., Mercer Co., PA $.29 per Mcf Barkeyville Borough, Venango Twp., PA 16% weighted average sales price Osnaburg Twp., Stark Co., OH 10% weighted average sales price Hanover Twp., Columbiana Co., OH 10% weighted average sales price Atwater Twp., Portage Co., OH 10% weighted average sales price Town of Sherman, Chatauqua Co., NY 10% weighted average sales price Blue Rock Twp., Muskingham Co., OH 10% weighted average sales price Perry Twp. Lake Co., OH 10% weighted average sales price Buffalo Twp., Noble Co., OH 10% weighted average sales price
EX-10 15 ex-10h.txt EXHIBIT 10(H) Exhibit 10(h) BASE CONTRACT FOR SALE AND PURCHASE OF NATURAL GAS DATED NOVEMBER 13, 2002 BETWEEN UGI ENERGY SERVICES, INC. AND VIKING RESOURCES CORP. Exhibit 10(h) ORIGINAL FILE COPY Base Contract for Sale and Purchase of Natural Gas This XXX of the following date, November 13, 2002. The parties for base contract are the following.
Viking Resources Corp. and UGI Energy Services, Inc. d/b/a GASMARK - -------------------------------------------------------- --------------------------------------------------------------- XXX 10500 1188 XXX Blvd., Suite 385, XXX - -------------------------------------------------------- --------------------------------------------------------------- Duns Number Duns Number 88-350-4581 - -------------------------------------------------------- --------------------------------------------------------------- Contract Number: Contract Number: - -------------------------------------------------------- --------------------------------------------------------------- U.S. Federal Tax ID Number: U.S. Federal Tax ID Number: 23-2800541 - -------------------------------------------------------- --------------------------------------------------------------- Notices: Viking Resources Corp. UGI Energy Services Inc. d/b/a GASMARK - -------------------------------------------------------- --------------------------------------------------------------- Attn: Michael Brecko Attn: Robert Meder - -------------------------------------------------------- --------------------------------------------------------------- Phone: (412) 262-2830 x126 Fax: (412) 262-3927 Phone: (610) 373 7999 Fax: (610) 374 4288 - -------------------------------------------------------- --------------------------------------------------------------- Confirmations: Viking Resources Corp. UGI Energy Services Inc. d/b/a GASMARK - -------------------------------------------------------- --------------------------------------------------------------- Attn: Michael Brecko Attn: Robert Meder - -------------------------------------------------------- --------------------------------------------------------------- Phone: (412) 262-2830 x126 Fax: (412) 262-3927 Phone: (610) 373 7999 Fax: (610) 374 4288 - -------------------------------------------------------- --------------------------------------------------------------- Invoices and Payments XXX XXX Attn: Attn: Joseph Hart - -------------------------------------------------------- --------------------------------------------------------------- Payments: Same Payments: Same - -------------------------------------------------------- --------------------------------------------------------------- Phone: Fax: Phone: (610) 373 7999 Fax: (610) 374 4288 - -------------------------------------------------------- --------------------------------------------------------------- Wire Transfer or ACH Numbers (if applicable) BANK: Koybank, Cleveland Ohio BANK: PNC Bank NA-Philadelphia - -------------------------------------------------------- --------------------------------------------------------------- ABA: D4100103XXX ABA: D3100003 ACCT: 428190700 ACCT: 8606074240 - -------------------------------------------------------- --------------------------------------------------------------- Other details: Account is with Resource Energy Other Details: - -------------------------------------------------------- --------------------------------------------------------------- This Base Contract incoporates by reference for all purposes the General Terms and Conditions for Sale and Purchase of Natural Gas published by the North American Energy Services Board. XXX General Terms and Conditions in the event the parties fail to check XXX the specified default provision shall apply XXX only one XXX from each section.
- ----------------------------------------------------------------------------------------------------------------------------------- Section 1.2 |_| Oral (default) Section 7.2 25th Day of Month following Month of delivery (default) Transaction |_| Written Payment Date 10 Days following receipt of Procedure |_| meter statements - ----------------------------------------------------------------------------------------------------------------------------------- Section 3 Business Days XXX Section XXX |_| XXX XXX |_| _____ Business Days after Method of |_| Automated Clearinghouse receipt Credit (ACH) XXX Payment |_| Other - ----------------------------------------------------------------------------------------------------------------------------------- Section 2.XXX |_| Seller (default) Section 7.7 |_| Nothing applies (default) Confirming |_| Buyer Nothing |_| Nothing does not apply Party |_| BOTH PARTIES - ----------------------------------------------------------------------------------------------------------------------------------- Section 3.2 |_| Cover Standard (default) Section 10.3.1 |_| Early Termination Damages Apply (default) Performance |_| Spot Price Standard Early Termination Damages |_| Early Termination Damages Do Obligation Not Apply -------------------------------------------------------------------- Note: The following Spot Price Publication applies to both Section 10.3.2 |_| Other Agreement XXXX Apply of the immediately preceding. (default) Other Agreements XXX |_| Other Agreements XXX Do Not Apply -------------------------------------------------------------------- Section 2.28 |_| Gas Daily Midpoint Section 14.5 (default) Spot Price |_| ___________________ Choice of Law Pennsylvania Publication - ----------------------------------------------------------------------------------------------------------------------------------- Section XXX |_| Buyer Pays At and After Section 14.10 |_| Confidentiality applies Delivery Point (default) (default) Confidentiality |_| Confidentiality does not apply Taxes |_| Seller Pays Before and At Delivery Point - ----------------------------------------------------------------------------------------------------------------------------------- |_| Special Provisions Number of sheets attached: 2 |_| Addendum(s): None - ----------------------------------------------------------------------------------------------------------------------------------- IN WITNESS WHEREOF, the parties hereto have executed this Base Contract in duplicate.
Viking Resources Corp. UGI Energy Services Inc. d/b/a GASMARK - -------------------------------------------------------- --------------------------------------------------------------- Party Name Party Name By: /s/ XXX Simmons By: /s/ Robert Meder - -------------------------------------------------------- --------------------------------------------------------------- Name: XXX Simmons Name: Robert Meder Title: Vice President Title: Vice President, Gas Supply & Risk Management - ----------------------------------------------------------------------------------------------------------------------------------- Copyright(C)2002 North American Energy Standards Board, Inc. NAESB Standard 6.3.1 All Rights Reserved April 19, 2002
GENERAL TERMS AND CONDITIONS BASE CONTRACT FOR SALE AND PURCHASE OF NATURAL GAS SECTION 1. PURPOSE AND PROCEDURES 1.1 These General Terms and Conditions are intended to facilitate purchase and sale transactions of Gas on a Firm or Interruptible basis. "Buyer" refers to the party receiving Gas and "Seller" refers to the party delivering Gas. The entire agreement between the parties shall be the Contract as defined in Section 2.7. THE PARTIES HAVE SELECTED EITHER THE "ORAL TRANSACTION PROCEDURE" OR THE "WRITTEN TRANSACTION PROCEDURE" AS INDICATED ON THE BASE CONTRACT. - ------------------------------------------------------------------------------- ORAL TRANSACTION PROCEDURE: - ------------------------------------------------------------------------------- 1.2 The parties will use the following Transaction Confirmation procedure. Any Gas purchase and sale transaction may be effectuated in an EDI transmission or telephone conversation with the offer and acceptance constituting the agreement of the parties. The parties shall be legally bound from the time they so agree to transaction terms and may each rely thereon. Any such transaction shall be considered a "writing" and to have been "signed". Notwithstanding the foregoing sentence, the parties agree that Confirming Party shall, and the other party may, confirm a telephonic transaction by sending the other party a Transaction Confirmation by facsimile, EDI or mutually agreeable electronic means within three Business Days of a transaction covered by this Section 1.2 (Oral Transaction Procedure) provided that the failure to send a Transaction Confirmation shall not invalidate the oral agreement of the parties, Confirming Party adopts its confirming letterhead, or the like, as its signature on any Transaction Confirmation as the identification and authentication of Confirming Party. If the Transaction Confirmation contains any provisions other than those relating to the commercial terms of the transaction (i.e., price, quantity, performance obligation, delivery point, period of delivery and/or transportation conditions), which modify or supplement the Base Contract or General Terms and Conditions of this Contract (e.g., arbitration or additional representations and warranties), such provisions shall not be deemed to be accepted pursuant to Section 1.3 but must be expressly agreed to by both parties; provided that the foregoing shall not invalidate any transaction agreed to by the parties. - ------------------------------------------------------------------------------- WRITTEN TRANSACTION PROCEDURE: - ------------------------------------------------------------------------------- 1.2 The parties will use the following Transaction Confirmation procedure. Should the parties come to an agreement regarding a Gas purchase and sale transaction for a particular Delivery Period, the Confirming Party shall, and the other party may, record that agreement on a Transaction Confirmation and communicate such Transaction Confirmation by facsimile, EDI or mutually agreeable electronic means, to the other party by the close of the Business Day following the date of agreement. The parties acknowledge that their agreement will not be binding until the exchange of non-conflicting, Transaction Confirmations of the passage of the Confirm Deadline without objection from the receiving party, as provided in Section 1.3. 1.3 If a sending party's Transaction Confirmation is materially different from the receiving party's understanding of the agreement referred to in Section 1.2, such receiving party shall notify the sending party via facsimile, EDI or mutually agreeable electronic means, by the Confirm Deadline, unless such receiving party has previously sent a Transaction Confirmation to the sending party. The failure of the receiving party to so notify the sending party in writing by the Confirm Deadline constitutes the receiving party's agreement to the terms of the transaction described in the sending party's Transaction Confirmation. If there are any material differences between timely sent Transaction Confirmations governing the same transaction, then neither Transaction Confirmation shall be binding until or unless such differences are resolved including the use of any evidence that XXX XXX the difference in the Transaction Confirmation. In the event of a conflict among the terms of (i) a binding Transaction Confirmation pursuant to Section 1.2, (ii) the oral agreement of the parties which may be evidenced by a recorded conversation, where the parties have selected the Oral Transaction Procedure of the Base Contract, (iii) the Base Contract, and (iv) these General Terms and Conditions, the terms of the documents shall govern in the priority listed in this sentence. 1.4 The parties agree that each party may electronically record all telephone conversations with respect to this Contract between their respective employees, without any special or further notice to the other party. Each party shall obtain any necessary consent of its agents and employees to such recording. Where the parties have selected the Oral Transaction Procedure in Section 1.2 of the Base Contract, the parties agree not to contest the validity or enforceability of telephonic recording entered into in accordance with the requirements of this Base Contract. However, nothing herein shall be construed as a waiver of any objection to the admissibility of such evidence. SECTION 2. DEFINITIONS The terms set forth below shall have the meaning ascribed to them below. Other terms are also defined elsewhere in the Contract and shall have the meanings ascribed to them herein: 2.1. "Alternative Damages" shall mean such damages, expressed in dollars or dollars per MMBtu, as the parties shall agree upon in the Transaction Confirmation, in the event either Seller or Buyer fails to perform a Firm obligation to deliver Gas in the case of Seller or to receive Gas in the case of Buyer. 2.2 "Base Contract" shall mean a contract executed by the parties that incorporates these General Terms and Conditions by reference; that specifies the agreed selections of provisions contained herein; and that sets forth other information required herein and any Special Provisions and addendum(s) as identified on page one. 2.3 "British thermal unit" or "Btu" shall mean the International BTU, which is also called Btu (IT). - ------------------------------------------------------------------------------- Copyright(C)2002 North American Energy Standards Board, Inc.NAESB Standard 6.3.1 All Rights Reserved Page 2 of 10 April 19, 2002 2.4. "Business Day" shall mean any day except Saturday, Sunday or Federal Reserve Bank holidays. 2.5. "Confirm Deadline" shall mean 5:00 p.m. in the receiving party's time zone on the second Business Day following the Day a Transaction Confirmation is received or, if applicable, on the Business Day agreed to by the parties in the Base Contract provided, if the Transaction Confirmation is time stamped after 5:00 p.m. in the receiving party's time zone, it shall be deemed received at the opening of the next Business Day. 2.6. "Confirming Party" shall mean the party designated in the Base Contract to prepare and forward Transaction Confirmations to the other party. 2.7. "Contract" shall mean the legally-binding relationship established by (i) the Base Contract, (ii) any and all binding Transaction Confirmations and (iii) where the parties have selected the Oral Transaction Procedure in Section 1.2 of the Base Contract, any and all transactions that the parties have entered into through an EDI transmission or by telephone, but that have not been confirmed in a binding Transaction Confirmation. 2.8. "Contract Price" shall mean the amount expressed in U.S. Dollars per MMBtu to be paid by Buyer to Seller for the purchase of Gas as agreed to by the parties in a transaction. 2.9. "Contract Quantity" shall mean the quantity of Gas to be delivered and taken as agreed to by the parties in a transaction. 2.10. "Cover Standard", as referred to in Section 3.2, shall mean that if there is an unexcused failure to take or deliver any quantity of Gas pursuant to this Contract, then the performing party shall use commercially reasonable efforts to (i) if Buyer is the performing party, obtain Gas, (or an alternate fuel if elected by Buyer and replacement Gas is not available), or (ii) if Seller is the performing party, sell Gas. In either case, at a price reasonable for the delivery or production area, as applicable, consistent with: the amount of notice provided by the nonperforming party; the immediacy of the Buyer's Gas consumption needs or Seller's Gas sales requirements, as applicable the quantities involved; and the anticipated length of failure by the nonperforming party. 2.11. "Credit Support Obligation(s)" shall mean any obligation(s) to provide or establish credit support for or on behalf of, a party to this Contract such as an irrevocable stand-by letter of credit, a margin agreement, a prepayment, a security interest in an asset, a performance bond, guaranty, or other bond and sufficient security of a continuing nature. 2.12. "Day" shall mean a period of 24 consecutive hours, coextensive with a "day" as defined by the Receiving Transporter in a particular transaction. 2.13. "Delivery Period" shall be the period during which deliveries are to be made as agreed to by the parties in a transaction. 2.14. "Delivery Points" shall mean such point(s) as are agreed to by the parties in a transaction. 2.15. "ED" shall mean an electronic data interchange pursuant to an agreement entered into by the parties, specifically relating to the communication of Transaction Confirmations under this Contract. 2.16. "EFP" shall mean the purchase, sale or exchange of natural Gas as the "physical" side of an exchange for physical transaction involving gas futures contracts. EFP shall incorporate the meaning and remedies of "Firm", provided that a party's excuse for nonperformance of its obligations to deliver or receive Gas will be governed by the rules of the relevant futures exchange regulated under the Commodity Exchange Act. 2.17. "Firms" shall mean that either party may interrupt its performance without liability only to the extent that such performance is prevented for reasons of "Force Majeure" provided, however, that during Force Majeure interruptions the party invoking Force Majeure may be responsible for any imbalance charges as set forth in Section 4.3 related to its interruption after the nomination is made to the Transporter and until the change in deliveries and/or receipts is confirmed by the Transporter. 2.18. "Gas" shall mean any mixture of hydrocarbons and noncombustible gases in a gaseous state consisting primarily of methane. 2.19. "Imbalance Charges" shall mean any fees, penalties, costs or charges (in cash or in kind) assessed by a Transporter for failure to satisfy the Transporter's balance and/or nomination requirements. 2.20. "Interruptible" shall mean that either party may interrupt its performance at any time for any reason, whether or not caused by an event of Force Majeure, with no liability, except such interrupting party may be responsible for any Imbalance Charges as set forth in Section 4.3 related to its interruption after the nomination is made to the Transporter and until the change in deliveries and/or receipts is confirmed by Transporter. 2.21. "MMBtu" shall mean one million British thermal units, which is equivalent to one dekatherm. 2.22. "Month" shall mean the period beginning on the first Day of the calendar month and ending immediately prior to the commencement of the first Day of the next calendar month. 2.23. "Payment Date" shall mean a date, as indicated on the Base Contract, on or before which payment is due Seller for Gas received by Buyer in the previous Month. 2.24. "Receiving Transporter" shall mean the Transporter receiving Gas at a Delivery Point, or absent such receiving Transporter, the Transporter delivering Gas at a Delivery Point. 2.25. "Scheduled Gas" shall mean the quantity of Gas confirmed by Transporter(s) for movement, transportation or management. 2.26. "Spot Price" as referred to in Section 3.2 shall mean the price listed in the publication indicated on the Base Contract, under the listing applicable to the geographic location closest in proximity to the Delivery Point(s) for the relevant Day; provided, if there is no single price published for such location for such Day, but there is published a range of prices, then the Spot Price shall be the average - ------------------------------------------------------------------------------- Copyright(C)2002 North American Energy Standards Board, Inc.NAESB Standard 6.3.1 All Rights Reserved Page 3 of 10 April 19, 2002 of such high and low prices. If no price or range of prices is published for such Day, then the Spot Price shall be the average of the following: (i) the price (determined as stated above) for the first Day for which a price or range of prices is published that next precedes the relevant Day; and (ii) the price (determined as stated above) for the first Day for which a price or range of prices is published that next follows the relevant Day. 2.27. "Transaction Confirmation" shall mean a document, similar to the form of Exhibit A, setting forth the terms of a transaction formed pursuant to Section 1 for a particular Delivery Period. 2.28. "Termination Option" shall mean the option of either party to terminate a transaction in the event that the other party fails to perform a Firm obligation to deliver Gas in the case of Seller or to receive Gas in the case of Buyer for a designated number of days during a period as specified on the applicable Transaction Confirmation. 2.29. "Transporter(s)" shall mean all Gas gathering or pipeline companies, or local distribution companies, acting in the capacity of a transporter, transporting Gas for Seller or Buyer upstream or downstream, respectively, of the Delivery Point pursuant to a particular transaction. SECTION 3. PERFORMANCE OBLIGATION 3.1. Seller agrees to sell and deliver, and Buyer agrees to receive and purchase, the Contract Quantity for a particular transaction in accordance with the terms of the Contract. Sales and purchases will be on a Firm or Interruptible basis, as agreed to by the parties in a transaction. The parties have selected either the "Cover Standard" or the "Spot Price Standard" as indicated on the Base Contract. - ------------------------------------------------------------------------------- Cover Standard: - ------------------------------------------------------------------------------- 3.2. The sole and exclusive remedy of the parties in the event of a breach of a Firm obligation to deliver or receive Gas shall be recovery of the following: (i) in the event of a breach by Seller on any Day(s), payment by Seller to Buyer in an amount equal to the positive difference, if any, between the purchase price paid by Buyer utilizing the Cover Standard and the Contract Price, adjusted for commercially reasonable differences in transportation costs to or from the Delivery Point(s), multiplied by the difference between the Contract Quantity and the quantity actually delivered by Seller for such Day(s); or (ii) in the event of a breach by Buyer on any Day(s), payment by Buyer to Seller in the amount equal to the positive difference, if any, between the Contract Price and the price received by Seller utilizing the Cover Standard for the resale of such Gas, adjusted for commercially reasonable differences in transportation costs to or from the Delivery Point(s), multiplied by the difference between the Contract Quantity and the quantity actually taken by Buyer for such Day(s); or (iii) in the event that Buyer has used commercially reasonable efforts to replace the Gas or Seller has used commercially reasonable efforts to sell the Gas to a third party, and no such replacement or sale is available, then the sole and exclusive remedy of the performing party shall be any unfavorable difference between the Contract Price and the Spot Price, adjusted for such transportation to the applicable Delivery Point multiplied by the difference between the Contract Quantity and the quantity actually delivered by Seller and received by Buyer for such Day(s). Imbalance Charges shall not be recovered under this Section 3.2, but Seller and/or Buyer shall be responsible for Imbalance Charges, if any, as provided in Section 4.3. The amount of such unfavorable difference shall be payable five Business Days after presentation of the performing party's invoice which shall set forth the basis upon which such amount was calculated. - ------------------------------------------------------------------------------- Spot Price Standard: - ------------------------------------------------------------------------------- 3.2. The sole and exclusive remedy of the parties in the event of a breach of a Firm obligation to deliver or receive Gas shall be recovery of the following: (i) in the event of a breach by Seller on any Day(s), payment by Seller to Buyer in an amount equal to the difference between the Contract Quantity and the actual quantity delivered by Seller and received by Buyer for such Day(s), multiplied by the positive difference, if any, obtained by subtracting the Contract Price from the Sport Price; or (ii) in the event of a breach by Buyer on any Day(s), payment by Buyer to Seller in an amount equal to the difference between the Contract Quantity and the actual quantity delivered by Seller and received by Buyer for such Day(s), multiplied by the positive difference, if any, obtained by subtracting the applicable Spot Price from the Contract Price. Imbalance Charges shall not be recovered under this Section 3.2, but Seller and/or Buyer shall be responsible for Imbalance Charges, if any, as provided in Section 4.3. The amount of such unfavorable difference shall be payable five Business Days after presentation of the performing party's invoice, which shall set forth the basis upon which such amount was calculated. - ------------------------------------------------------------------------------- 3.3. Notwithstanding Section 3.2, the parties may agree to Alternative Damages in a Transaction Confirmation executed in writing by both parties. 3.4. In addition to Sections 3.2 and 3.3, the parties may provide for a Termination Option in a Transaction Confirmation executed in writing by both parties. The Transaction Confirmation containing the Termination Option will designate the length of nonperformance triggering the Termination Option and the procedures for exercise thereof, how damages for nonperformance will be compensated, and how liquidation costs will be calculated. SECTION 4. TRANSPORTATION, NOMINATIONS, AND IMBALANCES 4.1. Seller shall have the sole responsibility for transporting the Gas to the Delivery Point(s). Buyer shall have the sole responsibility for transporting the Gas from the Delivery Point(s). 4.2. The parties shall coordinate their nomination activities, giving sufficient time to meet the deadlines of the affected Transporter(s). Each party shall give the other party timely prior Notice, sufficient to meet the requirements of all Transporter(s) involved in the transaction, of the quantities of Gas to be delivered and purchased each Day. Should either party become aware that actual deliveries at the Delivery Point(s) are greater or lesser than the Scheduled Gas, such party shall promptly notify the other party. - ------------------------------------------------------------------------------- Copyright(C)2002 North American Energy Standards Board, Inc.NAESB Standard 6.3.1 All Rights Reserved Page 4 of 10 April 19, 2002 4.3. The parties shall use commercially reasonable efforts to avoid imposition of any Imbalance Charges. If Buyer or Seller receives an invoice from a Transporter that includes Imbalance Charges, the parties shall determine the validity as well as the cause of such Imbalance Charges. If the Imbalance Charges were incurred as a result of Buyer's receipt of quantities of Gas greater than or less than the Scheduled Gas, then Buyer shall pay for such Imbalance Charges or reimburse Seller for such Imbalance Charges paid by Seller. If the Imbalance Charges were incurred as a result of Seller's delivery of quantities of Gas greater than or less than the Scheduled Gas, then Seller shall pay for such Imbalance Charges or reimburse Buyer for such Imbalance Charges paid by Buyer. SECTION 5. QUALITY AND MEASUREMENT All Gas delivered by Seller shall meet the pressure, quality and heat content requirements of the Receiving Transporter. The unit of quantity measurement for purposes of this Contract shall be one MMBtu dry. Measurement of Gas quantities hereunder shall be in accordance with the established procedures of the Receiving Transporter. SECTION 6. TAXES The parties have selected either "Buyer Pays At and After Delivery Point" or "Seller Pays Before and At Delivery Point" as indicated on the Base Contract. - ------------------------------------------------------------------------------- Buyer Pays At and After Delivery Point: - ------------------------------------------------------------------------------- Seller shall pay or cause to be paid all taxes, fees, levies, penalties, licenses or charges imposed by any government authority ("Taxes") on or with respect to the Gas prior to the Delivery Point(s). Buyer shall pay or cause to be paid all Taxes on or with respect to the Gas at the Delivery Point(s) and all Taxes after the Delivery Point(s). If a party is required to remit or pay Taxes that are the other party's responsibility hereunder, the party responsible for such Taxes shall promptly reimburse the other party for such Taxes. Any party entitled to an exemption from any such Taxes or charges shall furnish the other party any necessary documentation thereof. - ------------------------------------------------------------------------------- Seller Pays Before and At Delivery Point: - ------------------------------------------------------------------------------- Seller shall pay or cause to be paid all taxes, fees, levies, penalties, licenses or charges imposed by any government authority ("Taxes") on or with respect to the Gas prior to the Delivery Point(s) and all Taxes at the Delivery Point(s). Buyer shall pay or cause to be paid all Taxes on or with respect to the Gas after the Delivery Point(s). If a party is required to remit or pay Taxes that are the other party's responsibility hereunder, the party responsible for such Taxes shall promptly reimburse the other party for such Taxes. Any party entitled to an exemption from any such Taxes or charges shall furnish the other party any necessary documentation thereof. - ------------------------------------------------------------------------------- SECTION 7. BILLING, PAYMENT, AND AUDIT 7.1. Seller shall invoice Buyer for Gas delivered and received in the preceeding Month and for any other applicable charges, providing supporting documentation acceptable in industry practice to support the amount charged. If the actual quantity delivered is not known by the billing date, billing will be prepared based on the quantity of Scheduled Gas. The invoiced quantity will then be adjusted to the actual quantity on the following Month's billing or as soon thereafter as actual delivery information is available. 7.2. Buyer shall name the amount due under Section 7.1. in the manner specified in the Base Contract, in immediately available funds, on or before the later of the Payment Date or 10 Days after receipt of the invoice by Buyer, provided that if the Payment Date is not a Business Day, payment due on the next Business Day following that date, in the event any payments are due Buyer hereunder, payment to Buyer shall be made in accordance with the Section 7.2. 7.3. In the event payments become due pursuant to Sections 3.2 or 3.3, the performing party may submit an invoice to the nonperforming party for an accelerated payment setting forth the basis upon which the invoiced amount was calculated. Payment from the nonperforming party will be due five Business Days after receipt of invoice. 7.4. If the invoiced party, in good faith, disputes the amount of any such invoice or any part thereof, such invoiced party will pay such amount as it concedes to be correct, provided, however, if the invoiced party disputes the amount due, it must provide supporting documentation acceptable in industry practice to support the amount paid or disputed. In the event the parties are unable to resolve such dispute, either party may pursue any remedy available at law or in equity to enforce its rights pursuant to this Section. 7.5. If the invoiced party fails to remit the full amount payable when due, interest on the unpaid portion shall accrue from the date due until the date of payment at a rate equal to the lower of (i) the then effective prime rate of interest published under "Money Rates" by The Wall Street Journal plus two percent per annum; or (ii) the maximum applicable lawful interest rate. 7.6. A party shall have the right, at its own expense, upon reasonable Notice and at reasonable times, to examine and audit and to obtain copies of the relevant portion of the books, records, and telephone recordings of the other party only to the extent reasonably necessary to verify the accuracy of any statement, charge, payment, or computation made under the Contract. This right to examine, audit, and to obtain copies shall not be available with respect to proprietary information not directly relevant to transactions under this Contract. All invoices and billings shall be conclusively presumed final and accurate and all associated claims for under- or overpayments shall be deemed waived unless such invoices or billings are objected to in writing, with adequate explanation and/or documentation, within two years after the Month of Gas delivery. All retroactive adjustments under Section 7 shall be paid in full by the party owing payment within 30 Days of Notice and substantiation of such inaccuracy. 7.7. Unless the parties have elected on the Base Contract not to make this Section 7.7 applicable to this Contract, the parties shall net all undisputed amounts due and owing, and/or past due, arising under the Contract such that the party owing the greater amount shall make a single payment of the net amount to the other party in accordance with Section 7; provided that no payment required to be made pursuant to the terms of any Credit Support Obligation or pursuant to Section 7.3 shall be subject to netting under this Section. If the parties have executed a separate netting agreement, the terms and conditions therein shall prevail to the extent inconsistent herewith. - ------------------------------------------------------------------------------- Copyright(C)2002 North American Energy Standards Board, Inc.NAESB Standard 6.3.1 All Rights Reserved Page 5 of 10 April 19, 2002 SECTION 8. TITLE, WARRANTY, AND INDEMNITY 8.1. Unless otherwise specifically agreed, title to the Gas shall pass from Seller to Buyer at the Delivery Point(s). Seller shall have responsibility for and assume an liability with respect to the Gas prior to its delivery to Buyer at the specified Delivery Points(s). Buyer shall have responsibility for and any liability with respect to said Gas after its delivery to Buyer at the Delivery Points(s). 8.2. Seller warrants that it will have the right to convey and will transfer good and merchantable title to all Gas sold hereunder and delivered by it to Buyer, free and clear of all liens, encumbrances, and claims. EXCEPT AS PROVIDED IN THIS SECTION 8.2 AND IN SECTION 14.8, ALL OTHER WARRANTIES, EXPRESS OR IMPLIED, INCLUDING ANY WARRANTY OF MERCHANTABILITY OR OF FITNESS FOR ANY PARTICULAR PURPOSE ARE DISCLAIMED. 8.3. Seller agrees to indemnify Buyer and save it harmless from all losses, liabilities or claims including reasonable attorneys' fees and costs of court ("Claims"), from any and all persons, arising from or out of claims of title, personal injury or property damage from said Gas or other charges thereon which attach before title passes to Buyer. Buyer agrees to indemnify Seller and save it harmless from all Claims, from any and all persons, arising from or out of claims regarding payment, personal injury or property damage from said Gas or other charges thereon which attach after the passes to Buyer. 8.4. Notwithstanding the other provisions of this Section 8, as between Seller and Buyer, Seller will be liable for all Claims to the extent that such arise from the failure of Gas delivered by Seller to meet the quality requirement of Section 5. SECTION 9. NOTICES 9.1. At Transaction Confirmations, Invoices, payments and other communications made pursuant to the Base Contract ("Notices") shall be made to the addresses specified in writing by the respective parties from time to time. 9.2. All Notices required hereunder may be sent by facsimile or mutually acceptable electronic means, a nationally recognized overnight courier service, first class mail or hand delivered. 9.3. Notice shall be given when received on a Business Day by the addressee. In the absence of proof of the actual receipt date, the following presumptions will apply. Notices sent by facsimile shall be deemed to have been received upon the sending party's receipt or its facsimile machine's confirmation of successful transmission. If the day on which such facsimile is received is not a Business Day or is after five p.m. on a Business Day, then such facsimile shall be deemed to have been received on the next following Business Day. Notice by overnight mail or courier shall be deemed to have been received on the next Business Day after if was sent or such earlier time as is confirmed by the receiving party. Notice via first class mail shall be considered delivered five Business Days after mailing. SECTION 10. FINANCIAL RESPONSIBILITY 10.1. If either party ("X") has reasonable grounds for insecurity regarding the performance of any obligation under this Contract (whether or not then XXX) by the other party ("Y") (including, without limitation, the occurrence of a material change in the creditworthiness of Y), X may demand Adequate Assurance of Performance "Adequate Assurance of Performance" shall mean sufficient security in the form, amount and for the term reasonably acceptable to X including, but not limited to, a standby irrevocable letter of credit, a prepayment, a security interest in an asset or a performance bond or guaranty (including the issuer of any such security). 10.2. In the event [each an "Event of Default") either party (the "Defaulting Party") or its guarantor shall (i) make an assignment or any general arrangement for the benefit of creditors; (ii) XXX a petition or otherwise commence, authorize, or acquiesce in the commencement of a proceeding or case under any bankruptcy or similar law for the protection of creditors have such petition filed or preceding commenced against it; (iii) otherwise become bankrupt or insolvent (however evidenced); (iv) be unable to pay its debts as they fall due; (v) have a receiver, provisional liquidator, observator, custodian, trustee or other similar official appointed with respect to it or substantially all of its assets; (vi) fail to perform any obligation to the other party with respect to any Credit Support Obligations relating to the Contract; (vii) fail to give Adequate Assurance of Performance under Section 10.3 within 48 hours but at least one Business Day of a written request by the other party; or (viii) not have paid any amount due the other party hereunder on or before the second Business Day following written Notice that such payment is due; then the other party (the "Non-Defaulting Party") shall have the right, at its sole election, to immediately withhold and/or suspend deliveries or payments upon Notice and/or to terminate and liquidate the transactions under the Contract, in the manner provided in Section 10.3, in addition to any and all other remedies available hereunder. 10.3. If an Event of Default has occurred and is continuing, the Non-Defaulting Party shall have the right, by notice to the Defaulting Party, to designate a Day, no earlier than the Day such Notice is given and not later than 20 Days after such Notice is given, as an early termination date (the "Early Termination Date") for the liquidation and termination pursuant to Section 10.3.1 of all transactions under the Contract, each a "Terminated Transaction". On the Early Termination Date, all transactions will terminate, other than those transactions, if any, that may not be liquidated and terminated under applicable law or that are, in the reasonable opinion of the Non-Defaulting Party, commercially impracticable to liquidate and terminate ("Excluded Transactions"), which Excluded Transactions must be liquidated and terminated as seen thereafter as is reasonable practicable, and upon termination shall be a Terminated Transaction and be valued consistent with Section 10.3.1 below. With respect to each Excluded Transaction, its actual termination date shall be the Early Termination Date for the purposes of Section 10.3.1. - ------------------------------------------------------------------------------- Copyright(C)2002 North American Energy Standards Board, Inc.NAESB Standard 6.3.1 All Rights Reserved Page 6 of 10 April 19, 2002 THE PARTIES HAVE SELECTED EITHER "EARLY TERMINATION DAMAGES APPLY" OR "EARLY TERMINATION DAMAGES DO NOT APPLY" AS INDICATED ON THE BASE CONTRACT. - ------------------------------------------------------------------------------- EARLY TERMINATION DAMAGES APPLY: - ------------------------------------------------------------------------------- 10.3.1. As of the Early Termination Date, the Non-Defaulting Party shall determine, in good faith and in a commercially reasonable manner, (i) the amount owed (whether or not then due) by each party with respect to all Gas delivered and received between the parties under Terminated Transactions and Excluded Transactions on and before the Early Termination Date and all other applicable charges relating to such deliveries and receipts (including without limitation any amounts owed under Section 3.2), for which payment has not yet been made by the party that owes such payment under this Contract and (ii) the Market Value, as defined below, of each Terminated Transaction. The Non- Defaulting Party shall (x) liquidate and accelerate each Terminated Transaction at its Market Value, so that each amount equal to the difference between such market Value and the Contract Value, as defined below, of such Terminated Transaction(s) shall be due to the Buyer under the Terminated Transaction(s) if such Market Value exceeds the Contract Value and to the Seller if the opposite is the case; and (y) where appropriate, discount each amount then due under clause (x) above to present value in a commercially reasonable manner as of the Early Termination Date (to take account of the period between the date of liquidation and the date on which such amount would have otherwise been due pursuant to the relevant Terminated Transactions). For purposes of this Section 10.3.1. "Contract Value" means the amount of Gas remaining to be delivered or purchased under a transaction multiplied by the Contract Price, and "Market Value" means the amount of Gas remaining to be delivered or purchased under a transaction multiplied by the market price for a similar transaction at the Delivery Point determined by the Non-Defaulting Party in a commercially reasonable manner. To ascertain the Market Value, the Non-Defaulting Party may consider, among other valuations, any or all of the settlement prices of NYMEX Gas futures contracts, quotations from leading dealers in energy swap contracts or physical gas trading markets, similar sales or purchases and any other bona fide third-party offers, all adjusted for the length of the term and differences in transportation costs. A party shall not be required to enter into a replacement transaction(s) in order to determine the Market Value. Any extension(s) of the term of a transaction to which parties are not bound as of the Early Termination Date (including but not limited to "evergreen provisions") shall not be considered in determining Contract Values and Market Values. For the avoidance of doubt, any option pursuant to which one party has the right to o the terms of a transaction shall be considered in determining Contract Values and Market Values. The rate of interest used in calculating net present value shall be determined by the Non-Defaulting Party in a commercially reasonable manner. - ------------------------------------------------------------------------------- EARLY TERMINATION DAMAGES DO NOT APPLY: - ------------------------------------------------------------------------------- 10.3.1. As of the Early Termination Date, the Non-Defaulting Party shall determine, in good faith and in a commercially reasonable manner, the amount owed (whether or not then due) by each party with respect to all Gas delivered and received between the parties under Terminated Transactions and Excluded Transactions on and before the Early Termination Date and all other applicable charges relating to such deliveries and receipts (including without limitation any amount owed under Section 3.2), for which payment has not yet been made by the party that owes such payment under the Contract. - ------------------------------------------------------------------------------- THE PARTIES HAVE SELECTED EITHER "OTHER AGREEMENT SETOFFS APPLY" OR "OTHER AGREEMENT SETOFFS DO NOT APPLY" AS INDICATED ON THE BASE CONTRACT. - ------------------------------------------------------------------------------- OTHER AGREEMENT SETOFFS APPLY: - ------------------------------------------------------------------------------- 10.3.2. The Non-Defaulting Party shall net or aggregate, as appropriate, any and all amounts owing between the parties under Section 10.3.1. so that all such amounts are netted or aggregated to a single liquidated amount payable by one party to the other (the "Net Settlement Amount"). At its sole option and without prior Notice to the Defaulting Party, the Non-Defaulting Party may setoff (i) any Net Settlement Amount owed to the Non-Defaulting Party against any margin or other collateral held by it in connection with any Credit Support Obligation relating to the Contract; or (ii) any Net Settlement Amount payable to the Defaulting Party against any amount(s) payable by the Defaulting Party to the Non-Defaulting Party under any other agreement or arrangement between the parties. - ------------------------------------------------------------------------------- OTHERS AGREEMENT SETOFFS DO NOT APPLY: - ------------------------------------------------------------------------------- 10.3.2. The Non-Defaulting Party shall net or aggregate, as appropriate, any and all amounts owing between the parties under Section 10.3.1. so that all such amounts are netted or aggregated to a single liquidated amount payable by one party to the other (the "Net Settlement Amount"). At its sole option and without prior Notice to the Defaulting Party, the Non-Defaulting Party may setoff any Net Settlement Amount owed to the Non-Defaulting Party against any margin or other collateral held by it in connection with any Credit Support Obligation relating to the Contract. 10.3.3. If any obligation that is to be included in any netting, aggregation or setoff pursuant to Section 10.3.2 is unascertained, the Non- Defaulting Party may in good faith estimate that obligation and net, aggregate or setoff, as applicable, in respect of the estimate, subject to the Non- Defaulting Party accounting to the Defaulting Party when the obligation is ascertained. Any amount not then due which is included in any netting, aggregation or setoff pursuant to Section 10.3.2 shall be discounted to net present value in a commercially reaonable manner determined by the Non- Defaulting Party. 10.4. As soon as practicable after a liquidation, Notice shall be given by the Non-Defaulting Party to the Defaulting Party of the Net Settlement Amount, and whether the Net Settlement Amount is due to or due from the Non-Defaulting Party. The Notice shall include a written statement explaining in reasonable detail the calculation of such amount, provided that failure to give such Notice shall not affect the validity or enforceability of the liquidation or give rise to any claim by the Defaulting Party against the Non-Defaulting Party. The Net Settlement Amount shall be paid by the close of business on the second Business Day following such Notice, which date shall not be earlier than the Early Termination Date. Interest on any unpaid portion of the Net Settlement Amount shall accrue from the date due until the - ------------------------------------------------------------------------------- Copyright(C)2002 North American Energy Standards Board, Inc.NAESB Standard 6.3.1 All Rights Reserved Page 7 of 10 April 19, 2002 date of payment at a rate equal to the lower of (i) the then-effective prime rate of interest published under "Money Rates" by the The Wall Street Journal, plus two percent per annum, or (ii) the maximum applicable lawful interest rate. 10.5. The parties agree that the transactions hereunder constitute a "forward contract" within the meaning of the United States Bankruptcy Code and that Buyer and Seller are each "forward contract merchants" within the meaning of the United States Bankruptcy Code. 10.6. The Non-Defaulting Party's remedies under this Section 10 are the sole and exclusive remedies of the Non-Defaulting Party with respect to the occurrence of any Early Termination Date. Each party reserves to itself all other rights, setoffs, counterclaims and other defenses that it is or may be entitled to arising from the Contract. 10.7. With respect to this Section 10, if the parties have executed a separate netting agreement with close-out netting provisions, the terms and conditions therein shall prevail to the extent inconsistent herewith. SECTION 11. FORCE MAJEURE 11.1. Except with regard to a party's obligation to make payment(s) due under Section 7, Section 10.4, and imbalance Charges under Section 4, neither party shall be liable to the other for failure to perform a Firm obligation, to the extent such failure was caused by Force Majeure. The term "Force Majeure" as employed herein means any cause not reasonably within the control of the party claiming suspension, as further defined in Section 11.2. 11.2. Force Majeure shall include, but not be limited to, the following: (i) physical events such as acts of God, landslides, lightning, earthquakes, fires, storms or storm warnings, such as hurricanes, which result in evacuation of the affected area, floods, washouts, explosions, breakage or accident or necessity of repairs to machinery or equipment or lines of pipe, (ii) weather related events affecting an entire geographic region, such as low temperatures which cause freezing or failure of wells of lines of pipe; (iii) interruption and/or curtailment of Firm transportation and/or storage by Transporters; (iv) acts of others such as strikes, lockouts or other industrial disturbances, riots, sabotage, insurrections or wars; and (v) governmental actions such as necessary for compliance with any court order, law statute, ordinance, regulation or policy having the effect of law promulgated by a governmental authority having jurisdiction. Seller and Buyer shall make reasonable efforts to avoid the adverse impacts of a Force Majeure and to resolve the event or occurrence once it has occurred in order to resume performance. 11.3. Neither party shall be entitled to the benefit of the provisions of Force Majeure to the extent, performance is affected by any or all of the following occurrences: (i) the curtailment of interruptible or secondary Firm transportation unless primarily in-path, Firm transportation is also curtailed; (ii) the party claiming excuse failed to remedy the condition and to resume the performance of such covenants or obligations with reasonable dispatch; or (iii) economic hardship, to include without limitation, Seller's ability to sell Gas at a higher or more advantageous price than the Contract Price, Buyer's ability to purchase Gas at a lower or more advantageous price than the Contract Price or a regulatory agency disallowing, in whole or in part, the pass through of costs resulting from the Agreement, (iv) the loss of Buyer's market(s) or Buyer's inability to use or resell Gas purchased hereunder, except, in the either case, as provided in Section 11.2; (v) the loss or failure of Sellers gas supply or depletion of reserves, except in either case, as provided in Section 11.2. The party claiming Force Majeure shall not be excused from its responsibility for Imbalance Charges. 11.4. Notwithstanding anything to the contrary herein, the parties agree that the settlement of strikes, lockouts or other industrial disturbances shall be within the sole discretion of the party experiencing such disturbance. 11.5. The party whose performance is prevented by Force Majeure must provide Notice to the other party. Initial Notice may be given only, however, written Notices with reasonably full particulars of the event or occurrence is required as soon as reasonably possible. Upon providing written Notice of Force Majeure to the other party, the affected party will be relieved of its obligation, from the onset of the Force Majeure event to make or accept delivery of Gas as applicable, to the extent and for the duration of Force Majeure and neither party shall be deemed to have failed in such obligations to the other during such occurrence or event. 11.6. Notwithstanding Sections 11.2 and 11.3, the parties may agree to alternative Force Majeure provisions in a Transaction Confirmation executed in writing by both parties. SECTION 12. TERM The Contract may be terminated on 30 Days written Notice, but shall remain in effect until the expiration of the latest Delivery Period of any transaction(s). The rights of either party pursuant to Section 7.6 and Section 10, the obligations to make payment hereunder, and the obligation of either party to indemnify the other, pursuant hereto shall survive the termination of the Base Contract or any transaction. SECTION 13. LIMITATIONS FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY. A PARTY'S LIABILITY HEREUNDER SHALL BE LIMITED AS SET FORTH IN SUCH PROVISION, AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY PROVIDED HEREIN OR IN A TRANSACTION, A PARTY'S LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES ONLY. SUCH DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY, AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. UNLESS EXPRESSLY HEREIN PROVIDED, NEITHER PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE. - ------------------------------------------------------------------------------- Copyright(C)2002 North American Energy Standards Board, Inc.NAESB Standard 6.3.1 All Rights Reserved Page 8 of 10 April 19, 2002 TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID HEREUNDER ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OR OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT AND THE DAMAGES CALCULATED HEREUNDER CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR LOSS. SECTION 14. MISCELLANEOUS 14.1. This Contract shall be binding upon and inure to the benefit of the successors, assigns, personal representatives, and heirs of the respective parties hereto, and the covenants, conditions, rights and obligations of this Contract shall run for the full term of this Contract. No assignment of this Contract, in whole or in part, will be made without the prior written consent of the non-assigning party (and shall not relieve the assigning party from liability hereunder), which consent will not be unreasonably withheld or delayed; provided, either party may (i) transfer, sell, pledge, encumber, or assign this Contract or the accounts, revenues, or proceeds hereof in connection with any financing or other financial arrangements, or (ii) transfer its interest to any parent or affiliate by assignment, merger or otherwise without the prior approval of the other party. Upon any such assignment, transfer and assumption, the transferor shall remain principally liable for and shall not be relieved of or discharged from any obligations hereunder. 14.2. If any provision in this Contract is determined to be invalid, void or unenforceable by any court having jurisdiction, such determination shall not invalidate, void, or make unenforceable any other provision, agreement or covenant of this Contract. 14.3. No waiver of any breach of this Contract shall be held to be a waiver of any other or subsequent breach. 14.4. This Contract sets forth all understandings between the parties respecting each transaction subject hereto, and any prior contracts, understandings and representations, whether oral or written, relating to such transactions are merged into and superseded by this Contract and any effective transaction(s). This Contract may be amended only by a writing executed by both parties. 14.5. The interpretation and performance of this Contract shall be governed by the laws of the jurisdiction as indicated on the Base Contract, excluding, however, any conflict of laws rule which would apply the law of another jurisdiction. 14.6. This Contract and all provisions herein will be subject to all applicable and valid statutes, rules, orders and regulations of any governmental authority having jurisdiction over the parties, their facilities, or Gas supply, this Contract or transaction or any provisions thereof. 14.7. There is no third party beneficiary to this Contract. 14.8. Each party to this Contract represents and warrants that it has full and complete authority to enter into and perform this Contract. Each person who executes this Contract on behalf of either party represents and warrants that it has full and complete authority to do so and that such party will be bound thereby. 14.9. The headings and subheadings contained in this Contract are used solely for convenience and do not constitute a part of this Contract between the parties and shall not be used to construe or interpret the provisions of this Contract. 14.10. Unless the parties have elected on the Base Contract not to make this Section 14.10 applicable to this Contract, neither party shall disclose directly or indirectly without the prior written consent of the other party the terms of any transaction to a third party (other than the employees, lenders, royalty owners, counsel, accountants and other agents of the party, or prospective purchasers of all or substantially all of a party's assets or of any rights under this Contract, provided such persons shall have agreed to keep such terms confidential except (i) in order to comply with any applicable law, order, regulation, or exchange rule, (ii) to the extent necessary, for the enforcement of this Contract, (iii) to the extent necessary to implement any transaction, or (iv) to the extent such information is delivered to such third party for the sole purpose of calculating a published index. Each party shall notify the other party of any proceeding of which it is aware which may result in disclosure of the terms of any transaction (other than as permitted hereunder) and use reasonable efforts, to prevent or limit the disclosure. The existence of this Contract is not subject to this confidentiality obligation. Subject to Section 13, the parties shall be entitled to all remedies available at law or in equity to enforce, or seek relief in connection with this confidentiality obligation. The terms of any transaction hereunder shall be kept confidential by the parties hereto for one year from the expiration of the transaction. In the event that disclosure is required by a governmental body or applicable law, the party subject to such requirement may disclose the material terms of this Contract to the extent so required, but shall promptly notify the other party, prior to disclosure, and shall cooperate (consistent with the disclosing party's legal obligations) with the other party's efforts to obtain protective orders or similar restraints with respect to such disclosure at the expense of the other party. 14.11 The parties may agree to dispute resolution procedures in Special Provisions attached to the Base Contract or in a Transaction Confirmation executed in writing by both parties. DISCLAIMER: The purposes of this Contract are to facilitate trade, avoid misunderstandings and make more definite the terms of contracts of purchase and sale of natural gas. Further, NAESB does not mandate the use of this Contract by any party. NAESB DISCLAIMS AND EXCLUDES, AND ANY USER OF THIS CONTRACT ACKNOWLEDGES AND AGREES TO NAESB'S DISCLAIMER OF, ANY AND ALL WARRANTIES, CONDITIONS OR REPRESENTATIONS, EXPRESS OR IMPLIED, ORAL OR WRITTEN, WITH RESPECT TO THIS CONTRACT OR ANY PART THEREOF, INCLUDING ANY AND ALL IMPLIED WARRANTIES OR CONDITIONS OF TITLE, NON-INFRINGEMENT, MERCHANTABILITY, OR FITNESS OR SUITABILITY FOR ANY PARTICULAR PURPOSE (WHETHER OR NOT NAESB KNOWS, HAS REASON TO KNOW, HAS BEEN ADVISED, OR IS OTHERWISE IN FACT AWARE OF ANY SUCH PURPOSE), WHETHER ALLEGED TO ARISE BY LAW, BY REASON OF CUSTOM OR USAGE IN THE TRADE, OR BY COURSE OF DEALING. EACH USER OF THIS CONTRACT ALSO AGREES THAT UNDER NO CIRCUMSTANCES WILL NAESB BE LIABLE FOR ANY DIRECT, SPECIAL, INCIDENTAL, EXEMPLARY, PUNITIVE OR CONSEQUENTIAL DAMAGES ARISING OUT OF ANY USE OF THIS CONTRACT. - ------------------------------------------------------------------------------- Copyright(C)2002 North American Energy Standards Board, Inc.NAESB Standard 6.3.1 All Rights Reserved Page 9 of 10 April 19, 2002 EXHIBIT A TRANSACTION CONFIRMATION FOR IMMEDIATE DELIVERY
Viking Resources Corp Date: November 13, 2002 Transaction Confirmation #: ________________
This Transaction Confirmation is subject to the Base Contract between Seller and Buyer dated November 13, 2002 The terms of this Transaction Confirmation are binding unless disputed in writing within 2 Business Days of receipt unless otherwise specified in the Base Contract. - -------------------------------------------------------------------------------
SELLER: BUYER -------------------------------------------------------- ----------------------------------------------------------------------- Viking Resources Corp. UGI Energy Services, inc. d/p/a GASMARK -------------------------------------------------------- ----------------------------------------------------------------------- 311 Rouser Corp. 1100 Berkshire Blvd., Suite 305 -------------------------------------------------------- ----------------------------------------------------------------------- Wyomissing PA 19810 -------------------------------------------------------- ----------------------------------------------------------------------- Moon Two, PA 15108 Attn: Robert Meder -------------------------------------------------------- ----------------------------------------------------------------------- Attn: Michael Brecko Phone: 610-373-7999 -------------------------------------------------------- ----------------------------------------------------------------------- Phone: 412-282-2830-126 Fax: 610-374-4288 -------------------------------------------------------- ----------------------------------------------------------------------- Fax: 412-282-3927 Base Contract No. -------------------------------------------------------- ----------------------------------------------------------------------- Base Contract No. Transporter: -------------------------------------------------------- ----------------------------------------------------------------------- Transporter: Transporter Contract Number: -------------------------------------------------------- ----------------------------------------------------------------------- Transporter Contract Number: --------------------------------------------------------
- ------------------------------------------------------------------------------- Contract Price: $___________/MMBtu or NYMEX LDS plus $.30 oer Dth ____________________________ - ------------------------------------------------------------------------------- Delivery Period: Begin April 1, 2003 End: March 31, 2004 - ------------------------------------------------------------------------------- Performance Obligation and Contract Quantity: (Select One)
Firm (Fixed Quantity): Firm (Variable Quantity): Interruptible: __________________ MMBtus/day 9,000 MMBtus/day Minimum Up to _____________ MMBtus/day EFR 9,000 MMBtus/day Maximum subject to Section 4.2. at election of |_| Buyer or |_| Seller
- ------------------------------------------------------------------------------- Delivery Point(s): Texas Eastern Meter Number 73133 Station Name of Prah in Market areas M2 (If a o - ------------------------------------------------------------------------------- Special Conditions: Additional wells may be added upon mutual consent of the parties. All gas produced under this agreement shall be produced from wells located within the Commonwealth of Pennsylvania. Viking shall have trigger rights to lock its prices. - -------------------------------------------------------------------------------
Seller: Viking Resources Corp. Buyer: UGI Energy Services Inc., d/b/s GASMARK -------------------------------------------------------- ------------------------------------------------------------------------ By: By: -------------------------------------------------------- ------------------------------------------------------------------------ Title: Vice President Title: Vice President, Gas Supply & Risk Management -------------------------------------------------------- ------------------------------------------------------------------------ Date: 1/21/03 Date: 12/17/02 -------------------------------------------------------- ------------------------------------------------------------------------
- ------------------------------------------------------------------------------- Copyright(C)2002 North American Energy Standards Board, Inc.NAESB Standard 6.3.1 All Rights Reserved Page 10 of 10 April 19, 2002 SPECIAL PROVISIONS To Base Contract for Sale and Purchase of Natural Gas Between UGI Energy Services, Inc. and Viking Resources Corp. Dated November 13, 2002 THE FOLLOWING SENTENCE REPLACES SECTION 1.4 IN ITS ENTIRETY: The parties hereby consent to the electronic recording of their Oral Transactions and related telephone discussions. Each party waives any further notice of such recording, and agrees to notify its officers and employees of such recording and to obtain any necessary consent of such officers and employees. Failure by the Confirming Party to send, or the other party to return, an executed Transaction Confirmation shall not invalidate any Gas purchase and sale transaction (each a "Transaction" and collectively "Transactions") agreed to by the parties in a recorded telephone conversation. In the absence of a written Transaction Confirmation, any such recording will be deemed a "writing" by the parties for purposes of Section 2-201(1) of the Uniform Commercial Code. A true and complete copy of a recording made by either party will be provided to the other party upon request, if it reasonably appears that such recording may be utilized to resolve a dispute between the parities. Such recording may be submitted by either party as evidence of the existence or terms of a Transaction, subject to any applicable statute, rule or judicial precedent which limits the admissibility of parol or extrinsic evidence, and subject to any arguments which either party may make regarding the interpretation or significance of such recording. In the event of conflict between the terms and provisions of the written Transaction Confirmation and a recorded telephone conversation, the terms and provisions of the written Transaction Confirmation shall control to the extent of any such conflict. THE FOLLOWING REPLACES PARAGRAPH (i) IN SECTION 2.7: (i) the Base Contract, including the Special Provisions and any Addendums thereto, THE FOLLOWING REPLACES SECTION 2.20 IN ITS ENTIRETY: "Interruptible" shall mean that either party may interrupt its performance at any time for any reason, whether or not caused by an event of Force Majeure, with no liability, except such interrupting party may be responsible for any Imbalance Charges as set forth in Section 4.3, related to its interruption after the nomination is made to the Transporter and until the change in deliveries and/or receipts is confirmed by Transporter, or Section 4.4, related to the failure to provide timely notice of interruption. THE FOLLOWING PARAGRAPH IS ADDED AS SECTION 4.4: In the event that performance is interrupted, the interrupting party shall provide no less than 24 hours notice of its intent to interrupt. In the event the interrupting party fails to provide timely notice of its intent to interrupt its performance, the interrupting party shall be responsible for damages calculated using the standards set forth in Section 3.2. THE FOLLOWING IS ADDED AS THE FIRST SENTENCE IN SECTION 8.2: Seller warrants that it is fully capable of assuming and willing to assume, financially and otherwise, all of the duties and obligations of this Contract. THE FOLLOWING REPLACES SECTION 8.3 IN ITS ENTIRETY: Seller agrees to indemnify Buyer its successors and assigns, officers, directors and employees, and save them harmless from all losses, liabilities for claims, including but not limited to claims of title, personal injury, property damage, commercial damages and attorney's fees and costs of court ("Claims") arising from or out of or caused by Seller's possession or control of Gas sold hereunder. Buyer agrees to indemnify Seller its successors and assigns, officers, directors and employees, and save them harmless from all losses, liabilities for claims, including but not limited to claims of title, personal injury, property damage, commercial damages and attorney's fees and cost of court ("Claims") arising from or out of or caused by, Buyer's possession or control of Gas sold hereunder. THE FOLLOWING IS ADDED AT THE END OF SECTION 10.2: The Parties specifically agree that this Contract and all Transactions pursuant hereto are "Forward Contracts" as such term is defined in the United States Bankruptcy Code, 11 U.S.C., Section 101(25). If either Party becomes subject to Bankruptcy Code proceedings, it is understood and agreed that the other Party shall be entitled to exercise its right to liquidate this Contract as a "Forward Contract Merchant" under Section 556 of the U.S. Bankruptcy Code. THE FOLLOWING IS ADDED AT THE END OF THE SECOND PARAGRAPH IN SECTION 10.3.1 (EARLY TERMINATION DAMAGES APPLY): In addition to the other Early Termination Damages defined in this Section, the Non-Defaulting Party shall be entitled to recover the Costs resulting from the Event of Default. "Costs" shall mean brokerage fees, commissions and other similar transaction costs and expenses reasonably incurred by the Non- Defaulting Party either in terminating any arrangement by which it has hedged its obligations pursuant to a terminated EFP or Firm transaction or in entering into new arrangements which replace a terminated EFP or Firm transaction, and reasonable attorneys' fees, if any, incurred in connection with enforcing its rights hereunder.
Accepted and Approved: Accepted and Approved: UGI Energy Services, Inc. Viking Resources Corp. d/b/a GASMARK By: XXX By XXX - ---------------------------------- ---------------------------------- Title Title Vice President - ---------------------------------- ---------------------------------- Date 12/17/02 Date 1/21/03 - ---------------------------------- ----------------------------------
EX-23 16 ex-23a.txt EXHIBIT 23(A) EXHIBIT 23(a) CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS CONSENT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS We have issued our report dated June 30, 2004 on the balance sheet of Atlas America Public #14-2004 L.P. as of June 30, 2004 and our report dated December 5, 2003 accompanying the consolidated financial statements of Atlas Resources, Inc. as of September 30, 2003 and 2002 contained in the Registration Statement on Form S-1 and Prospectus for Atlas America Public #14-2004 Program. We consent to the use of the aforementioned reports in the Registration Statement and Prospectus, and to the use of our name as it appears under the caption "Experts". /s/ GRANT THORNTON LLP Cleveland, Ohio June 30, 2004 EX-24 17 ex-24.txt EXHIBIT 24 EXHIBIT 24 POWER OF ATTORNEY Exhibit 24 ATLAS AMERICA PUBLIC #14-2004 PROGRAM POWER OF ATTORNEY KNOW ALL MEN BY THESE PRESENTS, that each of the undersigned officers and/or directors of Atlas Resources, Inc., a Pennsylvania corporation which has filed with the Securities and Exchange Commission, under the provisions of the Securities Act of 1933, as amended, a Registration Statement on Form S-1 relating to certain securities of Atlas America Public #14-2004 Program, constitutes and appoints Jack L. Hollander, his/her true and lawful attorney-in-fact, with full power of substitution and resubstitution and with full power on the part of said attorney-in-fact to act without any other person, for him/her and in his/her name, place and stead, in any and all capacities, to sign such Registration Statement, and any and all amendments, including pre-effective amendments and post-effective amendments thereto, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission and all states and other jurisdictions wherein such Registration Statement and amendments thereto may be filed for securities compliance measures, granting unto said attorney-in-fact and agent, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he/she might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent, or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Dated: June 21, 2004 /s/ Freddie M. Kotek ---------------------------------------------------------------------- Freddie M. Kotek, Chairman of the Board of Directors, Chief Executive Officer and President Dated: June 28, 2004 /s/ Frank P. Carolas ---------------------------------------------------------------------- Frank P. Carolas, Executive Vice President - Land and Geology and a Director Dated: June 28, 2004 /s/ Jeffrey C. Simmons ---------------------------------------------------------------------- Jeffrey C. Simmons, Executive Vice President - Operations and a Director Dated: June 28, 2004 /s/ Nancy J. McGurk ---------------------------------------------------------------------- Nancy J. McGurk, Senior Vice President, Chief Financial Officer and Chief Accounting Officer
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