-----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, S8ETY2r+KSy1E4QVRMNgLw3iw3aF9ZdSOgMQh5Q7Nui5OJne4zCJ4K2or3neZq4u KpU7bp0S9+R7p9nkHWckCA== 0000950116-06-001372.txt : 20060428 0000950116-06-001372.hdr.sgml : 20060428 20060428144345 ACCESSION NUMBER: 0000950116-06-001372 CONFORMED SUBMISSION TYPE: 10-12G PUBLIC DOCUMENT COUNT: 17 FILED AS OF DATE: 20060428 DATE AS OF CHANGE: 20060428 FILER: COMPANY DATA: COMPANY CONFORMED NAME: Atlas America Public #15-2005 Program CENTRAL INDEX KEY: 0001335236 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 000000000 FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-12G SEC ACT: 1934 Act SEC FILE NUMBER: 000-51944 FILM NUMBER: 06789193 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 10-12G 1 form-10.txt As filed with the Securities and Exchange Commission on April 28, 2006 ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10 GENERAL FORM FOR REGISTRATION OF SECURITIES PURSUANT TO SECTION 12(B) OR (G) OF THE SECURITIES EXCHANGE ACT OF 1934 ATLAS AMERICA SERIES 26-2005 L.P. (Exact Name of registrant as specified in its charter) DELAWARE 20-2879859 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) 311 ROUSER ROAD MOON TOWNSHIP, PENNSYLVANIA 15108 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (412) 262-2830 Securities to be registered pursuant to Section 12(b)of the Act: NONE Securities to be registered pursuant to Section 12(g) of the Act: UNITS(1) (Title of Class) - ---------- (1) Units means limited partner units and investor general partner units, which will be automatically converted into limited partner units once our wells are drilled and completed.
TABLE OF CONTENTS PAGE PAGE ---- ---- Item 1 Business ....................................1 Our Managing General Partner's General....................................1 Management Obligations to Us Are Oil and Natural Gas Properties..........4 Not Exclusive, and if It Does Not Production..............................5 Devote the Necessary Time to Our Sale of Natural Gas and Oil Production..5 Management There Could Be Delays Major Customers.........................8 in Providing Timely Reports and Competition.............................8 Distributions to Our Participants, Markets.................................8 and Our Managing General Partner, Governmental Regulation....................8 Serving as Operator of Our Regulation of Production................9 Wells, May Not Supervise the Regulation of Transportation and Sale Wells Closely Enough ................15 of Natural Gas ........................9 Current Conditions May Change and Environmental Regulation...............11 Reduce Our Proved Reserves, Which Dismantlement, Restoration, Reclamation Could Reduce Our Revenues ...........16 and Abandonment Costs ................11 Government Regulation of the Oil and Employees..............................12 Natural Gas Industry is Stringent Item 1A Risk Factors.................................12 and Could Cause Us to Incur Risks Relating to Our Business............12 Substantial Unanticipated Costs Natural Gas and Oil Prices are Volatile for Regulatory Compliance, and a Substantial Decrease in Prices, Environmental Remediation of Our Particularly Natural Gas Prices, Well Sites (Which May Not Be Fully Would Decrease Our Revenues, Our Insured) and Penalties, and Could Cash Distributions and the Value Delay or Limit Our Drilling of Our Properties and Could Reduce Operations...........................17 Our Managing General Partner's Our Natural Gas and Oil Activities Are Ability to Loan Us Funds and Meet Subject to Drilling and Operating Its Ongoing Obligations to Hazards Which Could Result Indemnify Our Investor General in Substantial Losses to Us..........18 Partners and Purchase Units Our Total Annual Cash Distributions Under Our Presentment Feature........12 During Our First Five Years May be Drilling Wells is Highly Speculative Less than $2,500 Per Unit............18 and We Could Drill Some Wells That Increases in Drilling and Operating Are Nonproductive or That Costs Could Decrease Our Net Revenues Are Productive, But Fail to from Our Wells...................... 19 Return the Costs of Drilling and Our Limited Operating History Creates Operating Them, and the Drilling of Greater Uncertainty Regarding Our Some of Our Wells Could Be Curtailed, Ability to Operate Profitably........19 Delayed or Cancelled If Unexpected Competition May Reduce Our Revenues Events Occur ........................14 from the Sale of Our Natural Gas.....20
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TABLE OF CONTENTS PAGE PAGE ---- ---- We Sell Our Natural Gas to a Limited Since Our Managing General Partner Number of Purchasers Without Is Not Contractually Obligated to Guaranteed Prices, and if the Loan Funds to Us, We Could Have Prices Paid by the Purchasers to Curtail Operations or Sell Decrease, Our Revenues Also Will Properties if We Need Additional Decrease, and if a Purchaser Stops Funds and Our Managing General Buying Some or All of Our Natural Gas, Partner Does Not Make the Loan.......22 the Sale of Our Natural Gas Could Be Item 2 Financial Information.......................23 Delayed Until We Find Another Selected Financial Data...................23 Purchaser and the Substitute Forward Looking Statements................25 Purchaser We Find May Pay a Lower Results of Operations.....................25 Price, Which Would Reduce Liquidity and Capital Resources...........26 Our Revenues.........................20 Critical Accounting Policies..............26 We Could Incur Delays in Receiving Use of Estimates..........................27 Payment, or Substantial Losses if Reserve Estimates.........................27 Payment is Not Made, for Impairment of Oil and Gas Properties......27 Natural Gas We Previously Delivered Dismantlement, Restoration, Reclamation to a Purchaser, Which Could Delay and Abandonment Costs ...................28 or Reduce Our Revenues and Commodity Price Risk......................28 Cash Distributions...................21 Item 3 Properties..................................28 If Third-Parties Participating in Drilling Activity.........................28 Drilling Some of Our Wells Fail to Summary of Productive Wells...............29 Pay Their Share of the Well Production................................29 Costs, We Would Have to Pay Those Natural Gas and Oil Reserve Information...30 Costs in Order to Get the Wells Title to Properties.......................32 Drilled, and If We Are Not Acreage...................................33 Reimbursed the Increased Costs Item 4 Security Ownership of Certain Beneficial Would Reduce Our Cash Flow and Owners and Management ....................33 Possibly Could Reduce the Number of Item 5 Directors and Executive Officers............34 Wells We Can Drill...................21 Managing General Partner..................34 We Expect to Incur Costs in Connection Directors, Executive Officers and with Exchange Act Compliance and We Significant Employees....................36 May Become Subject to Code of Business Conduct and Ethics.......41 Liability for Any Failure to Comply, Organizational Charts....................41 Which Will Reduce Our Cash Available Item 6 Executive Compensation......................43 for Distribution.....................22 Item 7 Certain Relationships and Related We Intend to Produce Natural Gas and/or Transactions..............................44 Oil from Our Wells Until They Are Oil and Gas Revenues......................44 Depleted, Regardless of Any Changes Leases....................................44 in Current Conditions, Which Could Administrative Costs......................44 Result in Lower Returns to Our Direct Costs..............................44 Participants as Compared With Other Drilling Contracts........................44 Types of Investments Which Can Adapt to Future Changes Affecting Their Portfolios...........................22
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TABLE OF CONTENTS PAGE PAGE ---- ---- Per Well Charges..........................45 Term, Dissolution and Distributions Gathering Fees............................45 on Liquidation ..........................49 Dealer-Manager Fees.......................45 Transferability...........................50 Organization and Offering Costs...........45 Presentment Feature.......................51 Other Compensation........................45 Voting Rights and Amendments..............53 Item 8 Legal Proceedings...........................45 Books and Records.........................54 Item 9 Market Price of and Dividends on the Restrictions on Roll-Up Transactions......54 Registrant's Common Equity and Related Withdrawal of the Managing General Stockholder Matters ......................45 Partner..................................56 Item 10 Recent Sales of Unregistered Securities.....46 Item 12 Indemnification of Directors and Officers...56 Item 11 Description of Registrant's Securities to Item 13 Financial Statements and Supplementary Data.57 be Registered ............................47 Item 14 Changes in and Disagreements with General...................................47 Accountants on Accounting and Financial Liability of Participants for Further Disclosure................................ 74 Calls and Conversion..................... 47 Item 15 Financial Statements and Exhibits...........74 Distributions and Subordination...........48 Participant Allocations...................49
iii ITEM 1. BUSINESS. THE FOLLOWING DISCUSSION CONTAINS FORWARD-LOOKING STATEMENTS REGARDING EVENTS AND FINANCIAL TRENDS WHICH MAY AFFECT OUR FUTURE OPERATING RESULTS AND FINANCIAL POSITION. THESE STATEMENTS ARE SUBJECT TO RISKS AND UNCERTAINTIES THAT COULD CAUSE OUR ACTUAL RESULTS AND FINANCIAL POSITION TO DIFFER MATERIALLY FROM THE RESULTS ANTICIPATED IN THOSE STATEMENTS. THESE RISKS INCLUDE RISKS ASSOCIATED WITH DRILLING AND OPERATING OUR WELLS, MARKETING NATURAL GAS AND OIL PRODUCTION FROM THE WELLS, AND FLUCTUATIONS IN MARKET PRICES FOR THE NATURAL GAS AND OIL PRODUCED FROM THE WELLS. FOR A MORE COMPLETE DISCUSSION OF THE RISKS AND UNCERTAINTIES TO WHICH WE ARE SUBJECT, SEE "RISK FACTORS" IN ITEM 1A. THE TERMS "WE," "OUR", "US," "ITS" AND THE "COMPANY" USED IN THIS FORM 10 ARE USED AS REFERENCES TO ATLAS AMERICA SERIES 26-2005 L.P. GENERAL We were formed as a Delaware limited partnership on May 26, 2005, with Atlas Resources, Inc. as our managing general partner. Subsequently, in March 2006, Atlas Resources, Inc. was merged into Atlas Resources, LLC, a newly-formed Pennsylvania limited liability company. Our partnership operations began on our first closing on August 25, 2005. When we had our final closing on September 16, 2005, we had 579 investors who purchased our Units (our "participants"). "Units" means both our limited partner units and our investor general partner units that will automatically be converted into limited partner units once all of our wells are drilled and completed. In accordance with the terms of our offering, 1,338.98 Units were sold at $25,000 per Unit, 55.02 Units were sold at $23,250 per Unit to selling agents and their registered representatives and principals and clients of a registered investment advisor, and 869.412 Units were sold at $18,292 per Unit to our managing general partner, and its officers, directors and affiliates, and 6 Units were sold at 22,125 per Unit to investors who bought Units through the officers and directors of our managing general partner. Our participants contributed $34,886,500 in subscription proceeds to us, which we paid to our managing general partner serving as our operator and general drilling contractor under our drilling and operating agreement. We used all of our subscription proceeds to drill and complete wells located primarily in western Pennsylvania and central Tennessee as described below. Under our partnership agreement, all of the subscription proceeds of our participants were used to pay the intangible drilling costs of our wells and a portion of the tangible costs. "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. "Tangible costs" generally means the equipment costs of drilling and completing a well that are not currently deductible as intangible drilling costs and are not lease costs. Our managing general partner was required to contribute all of the leases on which our wells are situated, pay and/or contribute services towards our organization and offering costs up to an amount equal to 15% of our participants' subscription proceeds and pay the majority of our equipment costs to drill and complete our wells. As of December 31, 2005, the aggregate amount of these contributions by our managing general partner was $8,979,400. 1 Our investment objectives are to: o Provide monthly cash distributions from the wells drilled with our subscription proceeds until the wells are depleted, with minimum annual aggregate cash distributions per Unit to our participants equal to at least $2,500 (which is 10% of $25,000 per Unit, regardless of the actual subscription price paid) during the first five years beginning with our first distribution of production revenues to our participants. These distributions during the first five years are not guaranteed, but are subject to our managing general partner's subordination obligation as described in Item 11 "Description of Registrant's Securities to be Registered - Distributions and Subordination." Under current conditions, and based in part on the drilling results of our 99.3125 net initial wells (73% of our total estimated net wells) which were drilled in 2005, we believe that our participants will receive these minimum aggregate distributions of $2,500 per Unit per year during this five year period. See Item 3 "Properties" and Note 2 of the "Notes to Financial Statements" in Item 13 "Financial Statements and Supplementary Data." However, we do not yet know the drilling results of all of the approximately 35.375 net wells (27% of our total estimated net wells) which we prepaid in 2005 and are currently in the process of being drilled and completed as described more fully in Item 3 "Properties." Therefore, a participant should not place too much reliance on the results of the initial wells we drilled in 2005, until we have finished all of our drilling activities. Also, current conditions, such as prices for natural gas and our costs for operating our wells, will change during the next five years. See Item 1A "Risk Factors - Risks Relating to Our Business." o Obtain federal income tax deductions in 2005 from intangible drilling costs in an amount guaranteed to equal not less than 90% of each participant's subscription price for his or her Units. These deductions for intangible drilling costs may be used to offset a portion of the participant's taxable income, subject to any objections by the IRS, each participant's individual tax circumstances, and the passive activity rules if the participant invested in us as a limited partner. For example, if a participant paid $25,000 for a Unit the investment would produce a 2005 tax deduction of not less than $22,500 per unit, 90%, against: 2 o ordinary income, or capital gain in some situations, if the participant invested as an investor general partner; and o passive income if the participant invested as a limited partner. In the first quarter of 2006, our IRS Schedule K-1's to our participants reported a deduction for intangible drilling costs in 2005 in an amount equal to 90% of the subscription price paid by each participant. However, we do not guarantee the IRS treatment of our participants' deductions for intangible drilling costs. If the IRS were to decrease the amount of the deduction, or defer part of the deduction to 2006 for wells we prepaid in 2005, for example, our participants would not be entitled to any reimbursement from us for any increase in taxes owed, penalties or interest or any other lost tax benefits. o Offset a portion of any gross production income generated by us with tax deductions from percentage depletion. o Provide each of our participants with tax deductions, in an aggregate amount guaranteed to equal the remaining 10% of the participant's initial investment in us, through annual depreciation deductions over a seven-year cost recovery period. The tax benefits of these depreciation deductions to our participants are subject to any objections by the IRS, each participant's individual tax circumstances, and the passive activity rules if the participant invested as a limited partner or is a converted limited partner. Also, we do not guarantee the IRS treatment of our participants' depreciation deductions for our equipment costs. If the IRS were to decrease the amount of the deductions, for example, our participants would not entitled to any reimbursement from us for any increase in taxes owed, penalties or interest or any other lost tax benefits. We are filing this General Form for Registration of Securities on Form 10 to register our Units pursuant to Section 12(g) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). We are subject to the registration requirements of Section 12(g) because at the end of our first fiscal year on December 31, 2005, the aggregate value of our assets exceeded the applicable threshold of $10 million and our Units of record were held by more than 500 persons. Because of our obligation to register our Units with the Securities and Exchange Commission (the "SEC") under the Exchange Act, we will be subject to the requirements of the Exchange Act rules. In particular, we will be required to file: o quarterly reports on Form 10-QSB; o annual reports on Form 10-KSB; 3 o current reports on Form 8-K; and o otherwise comply with the disclosure obligations of the Exchange Act applicable to issuers filing registration statements pursuant to Section 12(g) of the Exchange Act. OIL AND NATURAL GAS PROPERTIES. We have drilled 99.3125 net development wells and are in the process of completing those wells. In addition, we are drilling and completing approximately 35.375 additional net development wells, the participants' costs of which were prepaid in 2005, but which were spudded in the first quarter of 2006. Because all of our wells have not yet been drilled and completed, our investor general partner units have not yet been converted to limited partner units. We will not drill any wells except the wells funded with our initial subscription proceeds and our managing general partner's capital contributions to us as described above. For further information concerning our natural gas and oil properties, including the number of wells in which we have a working interest and our reserve and acreage information, see Item 3 "Properties." We believe that our ongoing operating and maintenance costs for our productive wells will be paid through revenues we receive from the sale of our natural gas and oil production as discussed in Item 2 "Financial Information." Thus, the subscription proceeds from the offering of our Units in 2005 and our ongoing natural gas and oil production revenues from our wells will satisfy all of our cash requirements and we will not seek to raise additional funds from either our participants or new investors. We pay our managing general partner a monthly well supervision fee of $285 per well, as outlined in our drilling and operating agreement, for serving as the operator of our wells. This well supervision fee covers all normal and regularly recurring operating expenses for the production and sale of natural gas and to a lesser extent oil, such as: o well tending; o routine maintenance and adjustment; o reading meters and recording production; o pumping; o maintaining appropriate books and records; and o preparing reports to us and to government agencies. The well supervision fees, however, do not include costs and expenses related to the purchase of certain equipment, materials and brine disposal. If these expenses are incurred, we will pay these expenses at the invoice cost for third-party services and materials and we will pay a reasonable charge for services performed directly by our managing general partner or its affiliates. 4 PRODUCTION. All of our wells will produce, and some of our wells are currently producing, natural gas and to a far lesser extent oil, which are our only products. We do not plan to sell any of our wells and will continue to produce them until they are depleted, at which time they will be plugged and abandoned. See Item 3 "Properties" for information concerning: o our natural gas and oil production quantities; o average sales prices; and o average production costs. SALE OF NATURAL GAS AND OIL PRODUCTION. Our managing general partner is responsible for selling our natural gas and oil production. In the geographic areas where our wells are situated, our managing general partner is a party to natural gas contracts with various natural gas purchasers, each of which is paying a different price for our natural gas. To reduce the conflict of interest among us and our managing general partner's other partnerships concerning to whom and at what price our natural gas and oil will be sold, our managing general partner's policy is to treat all wells in any given geographic area equally by calculating a weighted average selling price for all of the natural gas sold in the geographic area. This is the price we and the other partnerships receive for our respective natural gas production in that geographic area. Our managing general partner is responsible for gathering and transporting the natural gas produced by us to interstate pipeline systems, local distribution companies, and/or end-users in the area. We will pay our managing general partner a competitive gathering fee for this service which our managing general partner anticipates currently will be an amount equal to 10% of the gross sales price received by us for our natural gas. However, in the following two areas, we will initially pay a lesser amount: o in the Armstrong County area our managing general partner anticipates that the gathering fee, if any, will be $.20 per mcf; and o in central Tennessee the gathering fee is $.55 per mcf for transportation of the natural gas plus actual costs for compression. Also, in the McKean County area, the gathering fees are an amount equal to 10% of the gross sales price received by us for our natural gas, plus $.35 per mcf if we use a third-party gathering line. Gross sales price means the price that is actually received by us, adjusted to take into account proceeds received or payments made pursuant to hedging arrangements which, for this purpose, include forward sales transactions. 5 For the majority of our natural gas production, our managing general partner will use the gathering system owned by Atlas Pipeline Partners, L.P., which is a master limited partnership operated by Atlas America, the indirect parent company of our managing general partner. See Item 5 "Directors and Executive Officers - Organizational Charts." Although Atlas America is 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, we will pay a lesser amount and Atlas America must pay the difference to Atlas Pipeline Partners. If our natural gas is not transported through the Atlas Pipeline Partners gathering system, it is because there is a third-party operator of our wells or the gathering system has not been extended to our wells. In these cases, our natural gas will be transported through a third-party gathering system, and we will pay our managing general partner a competitive gathering fee as described above, but which may be increased in the future. Once all of our wells are drilled, completed and online to sell production, the majority of our natural gas production initially will be sold to UGI Energy Services, Inc., since the majority of our wells have been or will be drilled in Fayette County, Pennsylvania, and the majority of our natural gas production from Fayette County will be sold to UGI Energy Services until March 31, 2007. In this regard, UGI Corporation has provided a $7 million guaranty of the payment obligations of UGI Energy Services, Inc. until March 31, 2007, subject to termination of the guarantee by UGI Corporation on 45 days prior written notice. Also, our natural gas production from the following areas initially will be sold as follows: o in Armstrong County the natural gas initially will be sold to U.S. Energy Exploration Corporation; o in McKean County the natural gas initially will be sold to M&M Royalty Ltd.; and o in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee the natural gas initially will be sold to Duke Energy. Our managing general partner anticipates that the remainder of our natural gas will be sold to Amerada Hess Corporation pursuant to a natural gas supply agreement which was first entered into with First Energy Solutions Corporation for a 10-year term which began on April 1, 1999, but is now effectively an agreement with Amerada Hess Corporation since First Energy Solutions Corporation has now been acquired by Amerada Hess Corporation. Under this agreement, Amerada Hess Corporation is to buy all of the natural gas produced and delivered by our managing general partner and its affiliates, which includes us and its other partnerships, subject to certain exceptions. Most of our natural gas, however, will not be sold pursuant to the agreement with Amerada Hess Corporation because of the exceptions in that agreement. The pertinent exceptions are natural gas sold through interconnects established after the date of the agreement with Amerada Hess Corporation, which includes the majority of natural gas produced from our wells in Fayette County and natural gas produced from our well(s) that are operated by a third-party or are subject to an agreement under which a third-party was to arrange for the gathering and sale of the natural gas such as natural gas produced from wells in Armstrong and McKean Counties, Pennsylvania and Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee. Our managing general partner cannot predict whether this will change in the future. 6 The delivery and pricing arrangements with our natural gas purchasers, including UGI Energy Services, Amerada Hess Corporation, Colonial Energy, U.S. Energy Exploration Corporation, M&M Royalty Ltd. and Duke Energy, are tied to the settlement New York Mercantile Exchange Commission ("NYMEX") monthly futures contracts price, which is reported daily in the Wall Street Journal, with an additional premium paid because of the location of the natural gas (the Appalachian Basin) in relation to the natural gas market, which is referred to as the "basis." The premium over quoted prices on the NYMEX received by our managing general partner and its affiliates has ranged between $.51 and $1.07 per mcf during the past three fiscal years. Pricing for natural gas and oil has been volatile and uncertain for many years. To limit our exposure to changes in natural gas prices our managing general partner uses forward sales transactions (which are not considered hedging for accounting purposes) through its natural gas purchasers as described below, and hedges through contracts such as regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The futures contracts employed by our 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, our managing general partner has established a committee to assure that all financial trading is done in compliance with our managing general partner's hedging policies and procedures. Our managing general partner does not intend to contract for positions that it cannot offset with actual production. Our natural gas purchasers, including UGI Energy Services, Amerada Hess Corporation and Colonial Energy, also use NYMEX based financial instruments to hedge their pricing exposure, and they make price hedging opportunities available to our managing general partner for us and our managing general partner's other partnerships. As of April 2, 2006, the majority of our managing general partner's natural gas was subject to forward sales transactions through March 31, 2007. The forward sales transactions are similar to NYMEX based futures contracts, swaps and options, but also require firm physical delivery of the natural gas. Because of this, our managing general partner limits these arrangements to much smaller quantities of natural gas than those projected to be available at any delivery point. Other than these forward sales transactions, we are not required to provide any fixed and determinable quantities of natural gas under any agreement. Also, the price paid by UGI Energy Services, Amerada Hess Corporation, Colonial Energy and any other third-party marketers for certain volumes of natural gas sold under these agreements may be significantly different from the underlying monthly spot market value. 7 The portion of natural gas that is subject to forward sales transactions and the form of the transaction (e.g. fixed pricing, floor and/or costless collar pricing) changes from time to time. In addition, on October 27, 2005, our managing general partner and its affiliates implemented financial hedges through its banking counter-party, Wachovia Bank, and as of April 2, 2006, our managing general partner and its affiliates have hedged approximately 63% of their production using fixed-for-floating financial swaps for the period April 1, 2007 though December 31, 2008, and approximately 21% for the period July 1, 2006 through December 31, 2009. It is difficult to project what portion of these forward sales transactions through the natural gas purchasers and hedges will be allocated to us by our managing general partner because of uncertainty about the quantity, timing, and delivery locations of natural gas that may be produced by us. Although hedging and the forward sales transactions provide us some protection against falling prices, these activities also could reduce the potential benefits of price increases. Crude oil produced from our wells will flow directly into storage tanks where it will be picked up by the oil company, a common carrier, or pipeline companies acting for the oil company which is purchasing the crude oil. Unlike natural gas, crude oil does not present any transportation problem. Our managing general partner anticipates selling any oil produced by our wells to regional oil refining companies at the prevailing spot market price for Appalachian crude oil in spot sales. MAJOR CUSTOMERS. Our natural gas and oil is sold under contract to various purchasers. For the period ended December 31, 2005, sales to U.S. Energy Exploration Corporation, Dominion Field Services, Inc. and Amerada Hess Corporation, accounted for 66%, 23%, 11%, respectively of total revenues. No other customer accounted for more than 10% of total revenues for the period ended December 31, 2005. COMPETITION. The energy industry is intensely competitive in all of its aspects. Competition arises not only from numerous domestic and foreign sources of natural gas and oil, but also from other industries that supply alternative sources of energy. In selling our natural gas and oil, product availability and price are our principal means of competition. We may also encounter competition in obtaining drilling and operating services from third-party providers. Any competition we encounter could delay the drilling and/or operating of our wells, and thus delay the distribution of our revenues to our participants. While it is impossible for us to accurately determine our comparative position in the natural gas and oil industry, we do not consider our operations to be a significant factor in the industry. MARKETS. The availability of a ready market for natural gas and oil, and the price obtained, depend on numerous factors beyond our control as described below in Item 1A "Risk Factors - Risks Relating to Our Business." During fiscal 2005, 2004, and 2003 our managing general partner did not experience problems in selling its and its affiliates' natural gas and oil, although prices varied significantly during and after those periods. 8 GOVERNMENTAL REGULATION REGULATION OF PRODUCTION. The production of natural gas and oil is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including the regulation of well spacing and plugging and abandonment of wells. The effect of these regulations is to limit the number of wells, or the locations where we can drill wells, although we can apply for exemptions to the regulations to reduce the well spacing. Also, each state generally imposes a production or severance tax for the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations. REGULATION OF TRANSPORTATION AND SALE OF NATURAL GAS. 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. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could re-enact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act, and in 1989 Congress enacted the Natural Gas Wellhead Decontrol Act that removed all price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993. Currently, 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. 9 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. 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. The energy industry in general is heavily regulated by federal and state authorities, including regulation of production, environmental quality and pollution control. The intent of federal and state regulations generally is to: o prevent waste; o protect rights to produce natural gas and oil between owners in a common reservoir; and o control contamination of the environment. Failure to comply with regulatory requirements can result in substantial fines and other penalties. State regulatory agencies where a producing natural gas well is located provide a comprehensive statutory and regulatory scheme for oil and natural gas operations such as ours, including supervising the production activities and the transportation of natural gas sold in intrastate markets. Our oil and gas operations in Pennsylvania are regulated by the Department of Environmental Resources, Division of Oil and Gas, our oil and gas operations in West Virginia are regulated by the West Virginia Department of Environmental Protection - Division of Oil and Gas, and our oil and gas operations in Tennessee are regulated by the Tennessee Dept. of Environment & Conservation, Div. of Geology. Among other things, the 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; 10 o discharge permits for drilling operations; o various reporting requirements; and o well plugging standards and procedures. ENVIRONMENTAL REGULATION. Our 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 us 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. 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. In addition, we 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 our drilling activities or the well and its production. Additionally, the well owners' or operators' liability can extend to pollution costs from situations that occurred before their acquisition of the well. Pennsylvania, West Virginia and Tennessee have either adopted federal standards or promulgated their own environmental requirements consistent with the federal regulations. We believe we have complied in all material respects with applicable federal and state regulations and do not expect that these regulations will have a material adverse impact on our operations. Although compliance may cause delays or increase our costs, currently we do not believe these costs will be substantial. However, we cannot predict the ultimate costs of complying with present and future environmental laws and regulations because these laws and regulations are constantly being revised, and ultimately they may have a material impact on our operations or costs to remain in compliance. Additionally, we cannot obtain insurance to protect against many types of environmental claims. DISMANTLEMENT, RESTORATION, RECLAMATION AND ABANDONMENT COSTS. When we determine that a well is no longer capable of producing natural gas or oil in economic quantities, we must dismantle the well and restore and reclaim the surrounding area before we can abandon the well. We contract these operations to independent service providers to which we pay a fee. The contractor will also salvage the equipment on the well, which we then sell in the used equipment market. Under the partnership agreement, our managing general partner and our participants are allocated abandonment costs in the same ratio in which they share in our production revenues (currently 38.31% to our managing general partner and 61.69% to our participants) and the salvage proceeds are allocated between our managing general partner and our participants in the same ratio in which they were charged with our equipment costs, which we estimate will charged be 74.18% to our managing general partner and 25.82% to our participants. 11 As a consequence of the allocation provisions of the partnership agreement described above, our managing general partner generally will receive proceeds from salvaged equipment at least equal to, and typically exceeding, its share of the related equipment costs, whereas our participants may have a shortfall. To cover our participants' potential shortfall, beginning one year after each of our wells has been placed into production our managing general partner, serving as operator, may retain $200 of our revenues per month to cover the estimated future plugging and abandonment costs of the well. See Notes to Financial Statements. EMPLOYEES. We have no employees. Instead, we rely on our managing general partner for management services, and our managing general partner relies on its parent company, Atlas America, Inc., for certain management and administrative services. See Item 5 "Directors and Executive Officers." ITEM 1A. RISK FACTORS Statements made by us that are not strictly historical facts are "forward-looking" statements that are based on current expectations about our business and assumptions made by our managing general partner. These statements are subject to risks and uncertainties that exist in our operations and business environment that could result in actual outcomes and results that are materially different than those predicted. The following section entitled "Risks Relating to Our Business" includes some, but not all, of those factors or uncertainties. RISKS RELATING TO OUR BUSINESS NATURAL GAS AND OIL PRICES ARE VOLATILE AND A SUBSTANTIAL DECREASE IN PRICES, PARTICULARLY NATURAL GAS PRICES, WOULD DECREASE OUR REVENUES, OUR CASH DISTRIBUTIONS AND THE VALUE OF OUR PROPERTIES AND COULD REDUCE OUR MANAGING GENERAL PARTNER'S ABILITY TO LOAN US FUNDS AND MEET ITS ONGOING OBLIGATIONS TO INDEMNIFY OUR INVESTOR GENERAL PARTNERS AND PURCHASE UNITS UNDER OUR PRESENTMENT FEATURE. A substantial decrease in natural gas and oil prices, particularly natural gas prices, would decrease our revenues and the value of our natural gas and oil properties. Our future financial condition and results of operations, and the value of our natural gas and oil properties, will depend on market prices for natural gas and, to a much lesser extent, oil. Further, if natural gas and oil prices decrease during the first years of production from our wells, which is when the wells typically achieve their greatest level of production, there would be a greater adverse effect on our distributions to our participants than price decreases in later years when the wells have a lower level of production. Also, our participants' return level will decrease during our term, even if there are rising natural gas prices, because of reduced production volumes from our wells. 12 Natural gas and oil prices historically have been volatile and will likely continue to be volatile in the future. Prices our managing general partner has received during its past three fiscal years for its natural gas have ranged from a high of $11.06 per mcf in the quarter ended December 31, 2005 to a low of $3.39 per mcf in the quarter ended December 31, 2001. Prices for natural gas and oil are dictated by supply and demand factors. 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 beyond our control 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 or terrorist acts in natural gas and oil producing countries; o the amount of domestic production of natural gas and oil; o the amount of foreign imports of natural gas and oil, including liquid natural gas from Canada and other countries (which our 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. 13 For example, the North American Free Trade Agreement ("NAFTA") eliminated trade and investment barriers in the United States, Canada, and Mexico. From time to time since then there have been increased imports 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 our wells. These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas and oil price movements with any certainty. Price decreases would reduce the amount of our cash flow available for distribution to our participants and could make some of our reserves uneconomic to produce which would reduce our reserves and cash flow. Additionally, price decreases may cause the lenders under our managing general partner's credit facility to reduce its borrowing base because of lower revenues or reserve values, which would reduce our managing general partner's liquidity, and, possibly, require mandatory loan repayments from our managing general partner. This would reduce our managing general partner's ability to loan us money or to meet its ongoing partnership obligations, such as indemnification of our investor general partners for liabilities in excess of their pro rata share of our assets and insurance proceeds and purchasing units presented by our participants, although this presentment right may be suspended by our managing general partner if it determines, in its sole discretion, that it does not have the necessary cash flow or cannot arrange for financing or other consideration for this purpose on reasonable terms. Also, see Item 5 "Directors and Executive Officers - Managing General Partner," regarding the reorganization of our managing general partner and its affiliates. Further, natural gas and oil prices do not necessarily move in tandem. Because the majority of our proved reserves are currently natural gas reserves, we are more susceptible to movements in natural gas prices. Also, even though hedging and forward sales transactions provide us some protection against falling natural gas prices, hedging and forward sales transactions 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 those arrangements. DRILLING WELLS IS HIGHLY SPECULATIVE AND WE COULD DRILL SOME WELLS THAT ARE NONPRODUCTIVE OR THAT ARE PRODUCTIVE, BUT FAIL TO RETURN THE COSTS OF DRILLING AND OPERATING THEM, AND THE DRILLING OF SOME OF OUR WELLS COULD BE CURTAILED, DELAYED OR CANCELLED IF UNEXPECTED EVENTS OCCUR. The amount of recoverable natural gas and oil reserves may vary significantly from well to well. We may drill some wells that are nonproductive (i.e. "dry holes"), or wells that are profitable on an operating basis, but do not produce sufficient net revenues to return a profit after drilling, operating and other costs are taken into account. The geologic data and technologies available do not allow us to know conclusively before drilling a well whether or not natural gas or oil is present or can be produced economically. 14 The cost of drilling, completing and operating a well is often uncertain. For example, our managing general partner has recently experienced an increase in the cost of tubular steel as a result of rising steel prices. This has increased our well costs since our wells are drilled by our managing general partner, serving as our general drilling contractor, at cost plus a nonaccountable fixed payment reimbursement to our managing general partner for our participants' share of our managing general partner's general and administrative overhead of $15,000 per well, plus 15% of the cost and the nonaccountable fee fixed payment reimbursement. Further, some of our drilling operations may be curtailed, delayed or cancelled as a result of many factors, including: o title problems; o environmental or other regulatory concerns; o costs of, or shortages or delays in the availability of, oil field services and equipment; o unexpected drilling conditions; o unexpected geological conditions; o adverse weather conditions; and o equipment failures or accidents. Any one or more of the factors discussed above could reduce or delay our receipt of natural gas and oil production revenues, thereby reducing or delaying distributions to our participants. As discussed in Item 3 "Properties," many of our prepaid wells are not yet completed and online. OUR MANAGING GENERAL PARTNER'S MANAGEMENT OBLIGATIONS TO US ARE NOT EXCLUSIVE, AND IF IT DOES NOT DEVOTE THE NECESSARY TIME TO OUR MANAGEMENT THERE COULD BE DELAYS IN PROVIDING TIMELY REPORTS AND DISTRIBUTIONS TO OUR PARTICIPANTS, AND OUR MANAGING GENERAL PARTNER, SERVING AS OPERATOR OF OUR WELLS, MAY NOT SUPERVISE THE WELLS CLOSELY ENOUGH. We do not have any officers, directors or employees. Instead, we rely totally on our managing general partner and its affiliates for our management. Our managing general partner is required to devote to us the time and attention that it considers necessary for the proper management of our activities. However, our managing general partner and its affiliates currently are, and will continue to be, engaged in other natural gas and oil activities, including other partnerships and unrelated business ventures for their own account or for the account of others, during our term. This creates a continuing conflict of interest in allocating management time, services, and other activities among us and its other activities. If our managing general partner does not devote the necessary time to our management, there could be delays in providing timely annual and semi-annual reports, tax information and cash distributions to our participants. Also, if our managing general partner, serving as the operator of our wells, does not supervise the wells closely enough, for example, there could be delays in undertaking remedial operations on a well, if necessary, to increase the production of natural gas and/or oil from the well. However, our managing general partner intends to allocate its management time, services and other functions on an as-needed basis consistent with its fiduciary duties among us and its other activities so that our administration as a partnership and our natural gas and oil operations are managed properly. 15 CURRENT CONDITIONS MAY CHANGE AND REDUCE OUR PROVED RESERVES, WHICH COULD REDUCE OUR REVENUES. A participant will be able to recover his investment in us only through our distribution 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. Our proved reserves will decline as they are produced from our wells, and once all of our wells are online our distributions to our participants generally will decrease each year until our wells are depleted. Our proved reserves at December 31, 2005 are set forth in Item 3 "Properties - Natural Gas and Oil Reserve Information." Under current conditions, our managing general partner is reasonably certain that those proved reserves will be produced over the life of our wells. However, there is an element of uncertainty in all estimates of proved reserves, and current conditions, such as natural gas and oil prices and the costs of operating our wells and transporting our natural gas, could change in the future and could reduce the amount of our current proved reserves. Thus, our revenues from the sale of our natural gas and oil production from our wells may vary significantly from our expectations associated with the current estimated proved reserves of our wells. We base our estimates of our proved natural gas and oil reserves and future net revenues from those reserves on analyses that rely on various assumptions, including those required by the SEC, as to natural gas and oil prices, taxes, development expenses, capital expenses, operating expenses and availability of funds. Any significant variance in the future in these assumptions, and, in our case, assumptions concerning future natural gas prices, could materially affect the estimated quantity of our reserves. Actual production, natural gas and oil prices, taxes, development expenses, operating expenses, availability of funds, and quantities of recoverable natural gas and oil reserves in the future may vary substantially from our estimates or the estimates contained in the reserve reports referred to in Item 3 "Properties." Our properties also may be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, our proved reserves may be revised downward in the future based on the following: o the actual production history of our wells; o results of future exploration and development in the area; 16 o prevailing natural gas and oil prices; o governmental regulation; and o other changes in current conditions, many of which are beyond our control. GOVERNMENT REGULATION OF THE OIL AND NATURAL GAS INDUSTRY IS STRINGENT AND COULD CAUSE US TO INCUR SUBSTANTIAL UNANTICIPATED COSTS FOR REGULATORY COMPLIANCE, ENVIRONMENTAL REMEDIATION OF OUR WELL SITES (WHICH MAY NOT BE FULLY INSURED) AND PENALTIES, AND COULD DELAY OR LIMIT OUR DRILLING OPERATIONS. We are subject to complex laws that can affect the cost, manner or feasibility of doing business. Exploration, development, production and sales of natural gas and oil are subject to extensive federal, state and local regulations. We discuss our regulatory environment in more detail in Item 1 "Business - Governmental Regulation." We may be required to make large expenditures to comply with these regulations. Failure to comply with these regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Other regulations may limit our operations. For example, "frost laws" prohibit drilling rigs and other heavy equipment from using certain roads during winter. This is important to us, because in 2005 we prepaid the costs of certain wells, including the currently deductible intangible drilling costs of the wells, and the drilling of each of those prepaid wells was to begin on or before March 30, 2006 under our drilling and operating agreement. Although the drilling of all of our prepaid wells began on or before March 30, 2006, government regulations such as the "frost laws" could delay the completion of our prepaid wells. Also, governmental regulations could change in ways that substantially increase our costs, thereby reducing our return on invested capital, revenues and net income. Our operations may cause us to incur substantial liabilities to comply with environmental laws and regulations. Our natural gas and oil operations are subject to stringent federal, state and local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may: o require the acquisition of a permit before drilling begins; o restrict the types, quantities, and concentration of substances that can be released into the environment in connection with drilling and production activities; o limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas; and 17 o impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the following: o assessment of administrative, civil, and criminal penalties; o incurrence of investigatory or remedial obligations; or o imposition of injunctive relief. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transporting, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance or could restrict our methods or times of operation. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or if our operations were standard in the industry at the time they were performed. We discuss the environmental laws that affect our operations in more detail under Item 1 "Business - Governmental Regulation - Environmental Regulation." Pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not covered, or not fully covered, by insurance could reduce our revenues and the value of our assets. OUR NATURAL GAS AND OIL ACTIVITIES ARE SUBJECT TO DRILLING AND OPERATING HAZARDS WHICH COULD RESULT IN SUBSTANTIAL LOSSES TO US. Well blowouts, cratering, explosions, uncontrollable flows of natural gas, oil or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks are inherent drilling and operating hazards for us. The occurrence of any of those hazards could result in substantial losses to us, including liabilities to third-parties or governmental entities for damages resulting from the occurrence of any of those hazards and substantial investigation, litigation and remediation costs. OUR TOTAL ANNUAL CASH DISTRIBUTIONS DURING OUR FIRST FIVE YEARS MAY BE LESS THAN $2,500 PER UNIT. If our participants' cash distributions from us are less than a 10% return of their capital (which is $2,500 per Unit based on a $25,000 Unit regardless of the actual price paid) for each of the first five 12-month periods beginning with our first cash distributions from operations, then our managing general partner has agreed to subordinate a portion of its share of our net production revenues. However, if our wells produce only small natural gas and oil volumes, and/or natural gas and oil prices decrease, then even with subordination our participants may not receive the 10% return of capital for each of the first five years as described above. Also, at any time during the subordination period our managing general partner is entitled to an additional share of our revenues to recoup previous subordination distributions to the extent our participants' cash distributions from us exceed the 10% return of capital described above. A more detailed discussion of our managing general partner's subordination obligation is set forth in Item 11 "Description of Registrant's Securities to be Registered - Distributions and Subordination." Also see "- Current Conditions May Change and Reduce Our Proved Reserves, Which Could Reduce Our Revenues," above. 18 INCREASES IN DRILLING AND OPERATING COSTS COULD DECREASE OUR NET REVENUES FROM OUR WELLS. The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oil field services, such as increased costs for tubular steel, have increased our drilling, completing and operating costs to some degree as compared to those well costs in our managing general partner's prior partnerships, and could decrease our net revenues from our wells. Although shortages of drilling rigs, equipment, supplies or personnel have not delayed the drilling of our wells, such shortages could delay completing some of our wells or connecting them to gathering lines, which would delay our receipt of production revenues from the wells. OUR LIMITED OPERATING HISTORY CREATES GREATER UNCERTAINTY REGARDING OUR ABILITY TO OPERATE PROFITABLY. Our limited history of operating our wells may not indicate the results that we may achieve in the future. Our success depends on generating sufficient revenues by producing sufficient quantities of natural gas and oil from our wells and then marketing that natural gas and oil at sufficient prices to pay the operating costs of our wells and our administrative costs of conducting business as a partnership, and still provide a reasonable rate of return on our participants' investment in us. If we are unable to pay our costs, then we may need to: o borrow funds from our managing general partner, which is not contractually obligated to make any loans to us; o shut-in or curtail production from some of our wells; or o attempt to sell some of our wells, which we may not be able to do on terms that are acceptable to us. Also, the events set forth below could decrease our revenues from our wells and/or increase our expenses of operating our wells: o decreases in the price of natural gas and oil, which are volatile; o changes in the oil and gas industry, including changes in environmental regulations, which could increase our costs of operating our wells in compliance with any new environmental regulations; 19 o an increase in third-party costs for equipment or services, or an increase in gathering and compression fees for transporting our natural gas production; and o problems with one or more of our wells, which could require repairing or performing other remedial work on a well or providing additional equipment for the well. COMPETITION MAY REDUCE OUR REVENUES FROM THE SALE OF OUR NATURAL GAS. 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 our natural gas. Our competitors may be able to offer their natural gas to natural gas purchasers on better terms, such as lower prices or a greater volume of natural gas that can be delivered to the purchaser, which we cannot match. Also, other energy sources such as coal may be available to the purchasers at a lower price. As a result, we may have to seek other natural gas purchasers and we may receive lower prices for our natural gas and incur higher transportation and compression fees if we sell our natural gas to these other natural gas purchasers. In this event, our revenues from the sale of our natural gas would be reduced. WE SELL OUR NATURAL GAS TO A LIMITED NUMBER OF PURCHASERS WITHOUT GUARANTEED PRICES, AND IF THE PRICES PAID BY THE PURCHASERS DECREASE, OUR REVENUES ALSO WILL DECREASE, AND IF A PURCHASER STOPS BUYING SOME OR ALL OF OUR NATURAL GAS, THE SALE OF OUR NATURAL GAS COULD BE DELAYED UNTIL WE FIND ANOTHER PURCHASER AND THE SUBSTITUTE PURCHASER WE FIND MAY PAY A LOWER PRICE, WHICH WOULD REDUCE OUR REVENUES. We will depend initially on a limited number of natural gas purchasers to purchase the majority of our natural gas production as described in Item 1 "Business - General - Sale of Natural Gas and Oil Production" and "- General - Major Customers," and we will not be guaranteed a specific natural gas price, other than through hedging and forward sales transactions. For example, for the period ended December 31, 2005, U.S. Energy Exploration Corporation, Dominion Field Services, Inc., and Amerada Hess Corporation accounted for 66%, 23%, and 11%, respectively, of total revenues. No other customer accounted for 10% or more of total revenues for the period ended December 31, 2005. Thus, if our current purchasers, including UGI Energy Services, Inc., Amerada Hess Corporation, and U.S. Energy Exploration Corporation were to pay a lower price for our natural gas in the future, our revenues would decrease. Also, if our current purchasers, including UGI Energy Services, Inc., Amerada Hess Corporation and U.S. Energy Exploration Corporation, were to begin buying a reduced percentage of our natural gas, or stopped buying any of our natural gas, the sale of our natural gas could be delayed until we find another purchaser, and the substitute purchaser or purchasers we do find may pay lower prices for our natural gas, which would reduce our revenues. However, our managing general partner has not experienced any problems with selling natural gas in the past three fiscal years as discussed in Item 1 "Business - General - Markets." 20 Also, our managing general partner anticipates that it will use the gathering system owned by Atlas Pipeline Partners for the majority of our natural gas as described in Item 1 "Business - General - Sale of Natural Gas and Oil Production." Atlas Pipeline Partners GP, LLC, a wholly-owned subsidiary of Atlas Pipeline Holdings, L.P., an affiliate of Atlas America, Inc., which is sometimes referred to in this Form 10 as "Atlas America" and is the indirect parent company of our managing general partner, controls and manages the gathering system for Atlas Pipeline Partners. (See Item 5 "Directors and Executive Officers - Organizational Charts.") Atlas Pipeline Holdings, L.P., as a public company, may be more susceptible to a change of control from Atlas America's affiliates to independent third-parties. Also, if Atlas Pipeline Partners GP, LLC were removed as general partner of Atlas Pipeline Partners without cause and without its consent, this could increase the amount of gathering fees required to be paid by us for natural gas transported through Atlas Pipeline Partners' gathering system. This could happen, because Atlas Pipeline Partners GP, LLC would no longer receive revenues from Atlas Pipeline Partners, but Atlas America and its affiliates would be obligated to pay the difference between the amount in the master natural gas gathering agreement and the amount paid by us. Although there is an exception with respect to new wells drilled after the removal of the general partner, we do not anticipate that we would still be drilling new wells at that time. Thus, our managing general partner and its affiliates may have an incentive to increase the gathering fees we pay, which would reduce our cash distributions. WE COULD INCUR DELAYS IN RECEIVING PAYMENT, OR SUBSTANTIAL LOSSES IF PAYMENT IS NOT MADE, FOR NATURAL GAS WE PREVIOUSLY DELIVERED TO A PURCHASER, WHICH COULD DELAY OR REDUCE OUR REVENUES AND CASH DISTRIBUTIONS. There is a credit risk associated with a natural gas purchaser's ability to pay. We may not be paid or may experience delays in receiving payment for natural gas that has already been delivered. In this event, our revenues and cash distributions to our participants also would be delayed or reduced. In accordance with industry practice, we typically will deliver natural gas to a purchaser for a period of up to 60 to 90 days before we receive payment. Thus, it is possible that we 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 our natural gas. This credit risk may also reduce the price benefit derived by us from our managing general partner's natural gas forward sales transactions as described in Item 1 "Business - General - Sale of Natural Gas and Oil Production," since a portion of our managing general partner's natural gas is subject to forward sales transactions implemented through the natural gas purchasers. IF THIRD-PARTIES PARTICIPATING IN DRILLING SOME OF OUR WELLS FAIL TO PAY THEIR SHARE OF THE WELL COSTS, WE WOULD HAVE TO PAY THOSE COSTS IN ORDER TO GET THE WELLS DRILLED, AND IF WE ARE NOT REIMBURSED THE INCREASED COSTS WOULD REDUCE OUR CASH FLOW AND POSSIBLY COULD REDUCE THE NUMBER OF WELLS WE CAN DRILL. Third-parties have participated with us in drilling some of our wells. Financial risks exist when the cost of drilling, equipping, completing, and operating wells is shared by more than one person. If we pay our share of the costs, but the other interest owner does not pay its share of the costs, then we would have to pay the costs of the defaulting party. In this event, we would receive the defaulting party's revenues from the well, if any, under penalty arrangements set forth in the operating agreement, which may, or may not, be sufficient to cover the additional costs we paid and, if not, then the increased costs would reduce our cash flow and the number of wells we can drill unless we borrow funds to cover the additional costs or the costs of drilling our other wells is less than expected and those excess funds are used to pay the additional costs that should have been paid by the third-party. However, the third-parties participating in some of our wells currently have not defaulted on any of their respective obligations for those wells. 21 WE EXPECT TO INCUR COSTS IN CONNECTION WITH EXCHANGE ACT COMPLIANCE AND WE MAY BECOME SUBJECT TO LIABILITY FOR ANY FAILURE TO COMPLY, WHICH WILL REDUCE OUR CASH AVAILABLE FOR DISTRIBUTION. As a result of our obligation to register our securities with the SEC under the Exchange Act, we will be subject to Exchange Act Rules and related reporting requirements. This compliance with the reporting requirements of the Exchange Act will require timely filing of quarterly reports on Form 10-QSB, annual reports on Form 10-KSB and current reports on Form 8-K, among other actions. Further, recently enacted and proposed laws, regulations and standards relating to corporate governance and disclosure requirements applicable to public companies, including the Sarbanes-Oxley Act of 2002 (the "Sarbanes-Oxley Act") and new SEC regulations, have increased the costs of corporate governance, reporting and disclosure practices which are now required of us. In addition, these laws, rules and regulations create new legal grounds for administrative enforcement and civil and criminal proceedings against us in case of non-compliance, which increases our risks of liability and potential sanctions. All of the additional compliance costs described above will decrease the amount of cash available to us to distribute to our participants. WE INTEND TO PRODUCE NATURAL GAS AND/OR OIL FROM OUR WELLS UNTIL THEY ARE DEPLETED, REGARDLESS OF ANY CHANGES IN CURRENT CONDITIONS, WHICH COULD RESULT IN LOWER RETURNS TO OUR PARTICIPANTS AS COMPARED WITH OTHER TYPES OF INVESTMENTS WHICH CAN ADAPT TO FUTURE CHANGES AFFECTING THEIR PORTFOLIOS. Our natural gas and oil properties are relatively illiquid because there is no public market for working interests in natural gas and oil wells. In addition, one of our investment objectives is to continue to produce natural gas and oil from our wells until the wells are depleted. Thus, unlike mutual funds, for example, which can vary their portfolios in response to changes in future conditions, we do not intend, and in all likelihood we would be unable, to vary our portfolio of wells in response to future changes in economic and other conditions such as decreases or increases in natural gas or oil prices, or increased operating costs of our wells. SINCE OUR MANAGING GENERAL PARTNER IS NOT CONTRACTUALLY OBLIGATED TO LOAN FUNDS TO US, WE COULD HAVE TO CURTAIL OPERATIONS OR SELL PROPERTIES IF WE NEED ADDITIONAL FUNDS AND OUR MANAGING GENERAL PARTNER DOES NOT MAKE THE Loan. We believe that our ongoing operating and maintenance costs for our productive wells will be paid through revenues we receive from the sale of our natural gas and oil production as discussed in Item 2 "Financial Information." However, a shortfall in funds to pay for our ongoing expenses may arise, for example, for costs associated with repairing or performing other remedial work on a well. If this were to occur, we expect that we would borrow the necessary funds from our managing general partner or its affiliates, which are not contractually committed to make a loan. The amount we may borrow may not at any time exceed 5% of our total subscriptions and no borrowings will be obtained from third-parties. If, for any reason, our managing general partner did not loan us the funds needed for repairing or performing other remedial work on a well, then we might have to curtail our operations on the well or wells which needed the remedial work or we may attempt to sell one or more of our wells, although we may not be able to do so on terms that are acceptable to us. 22 ITEM 2. FINANCIAL INFORMATION. SELECTED FINANCIAL DATA. The following table sets forth selected financial data for the period ended December 31, 2005, that we derived from our financial statements, which were audited by Grant Thornton LLP, independent registered public accountants, and are included in this Form 10.
FOR THE PERIOD MAY 26, 2005 (DATE OF FORMATION) THROUGH DECEMBER 31, 2005 --------------------------------------- INCOME STATEMENT DATA: Revenues: Gas and oil production .................................................. $34,700 --------- Total revenues....................................................... $34,700 ========= Costs and expenses: Gas and oil production.................................................... $2,100 Transmission.............................................................. 400 General and administration................................................ 13,600 Depletion................................................................. 7,600 --------- Total costs and expenses....................................................... $23,700 ========= Net income..................................................................... 11,000 --------- Basic and diluted net earnings per limited partnership unit.................... $3 =========
23
FOR THE PERIOD MAY 26, 2005 (DATE OF FORMATION) THROUGH DECEMBER 31, 2005 ---------------------------- OPERATING DATA: Net annual production volumes: Natural gas (mmcf) (1) .................................................. 3,073 Oil (mbbls).............................................................. - ----------- Total (mmcfs).................................................................. 3,073 =========== Average sales price: Natural gas (per mcf).................................................... $11.31 Oil (per bbl) ........................................................... $- OTHER FINANCIAL INFORMATION: Net cash used in operating activities.......................................... $17,219,700 Capital expenditures .......................................................... $17,666,800 EBITDA (2).................................................................... $18,600
FOR THE PERIOD MAY 26, 2005 (DATE OF FORMATION) THROUGH DECEMBER 31, 2005 --------------------------------- BALANCE SHEET DATA: Total assets................................................................... $39,922,900 =========== Total liabilities ............................................................ $581,100 =========== Partners' capital.............................................................. $39,341,800 ===========
(1) Excludes sales of residual gas and sales to landowners. (2) We define EBITDA as earnings before interest, taxes, depreciation, depletion and amortization. EBITDA is not a measure of performance calculated in accordance with accounting principles generally accepted in the United States of America or GAAP. Although not prescribed under GAAP, we believe the presentation of EBITDA is relevant and useful because it helps our participants to understand our operating performance and makes it easier to compare our results with other companies that have different financing and capital structures or tax rates. EBITDA should not be considered in isolation from, or as a substitute for, our net income as an indicator of operating performance or cash flows from operating activities as a measure of liquidity. EBITDA, as we calculate it, may not be comparable to EBITDA measures reported by other companies. In addition, EBITDA does not represent funds available for discretionary use. The following reconciles EBITDA to our income from continuing operations for the periods indicated. 24
FOR THE PERIOD MAY 26, 2005 (DATE OF FORMATION) THROUGH DECEMBER 31, 2005 -------------------------------------- Income from continuing operations............................................... $11,000 Plus depletion ................................................................. 7,600 ------- EBITDA.......................................................................... $18,600 =======
FORWARD-LOOKING STATEMENTS. When used in this Form 10, the words "believes," "anticipates," "expects" and similar expressions are intended to identify forward-looking statements. These statements are subject to certain risks and uncertainties more particularly described in Item 1A "Risk Factors" of this Form 10. These risks and uncertainties could cause our actual results to differ materially from those that we anticipate. Readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this Form 10. We undertake no obligation to publicly release the results of any revisions to forward-looking statements that we may make to reflect events or circumstances after the date of this Form 10 or to reflect the occurrence of unanticipated events. This "Financial Information" section should be read in conjunction with Item 13 "Financial Statements and Supplementary Data - Notes to Financial Statements." RESULTS OF OPERATIONS. The following table sets forth information for the period May 26,2005 (date of formation) through December 31, 2005 relating to revenues recognized and costs and expenses incurred, daily production volumes, average sales prices and production cost per equivalent unit during the period indicated:
PERIOD ENDED DECEMBER 31, 2005 -------------------------------------- Revenues (in thousands): Gas(1) ............................................................ $34,747 Oil................................................................ $- Production volumes: Gas (thousands of cubic feet (mcf)/day)............................ 29 Oil (barrels (bbls)/day)........................................... - Average sales price: Gas (per mcf)...................................................... $11.31 Oil (per bbl)...................................................... $- Production costs: As a percent of sales.............................................. 7% Per equivalent mcf................................................. $.81 Depletion per mcfe...................................................... $2.48
- --------- (1) Excludes sales of residual gas and sales to landowners. 25 LIQUIDITY AND CAPITAL RESOURCES. Cash used in investing activities was $17,666,800 for the period ended December 31, 2005, which was paid to our managing general partner, serving as general drilling contractor, pursuant to our drilling and operating agreement. Cash provided by financing activities was $34,886,600 which came from capital contributions for the period ended December 31, 2005. Our managing general partner believes that we have adequate capital to develop approximately 144 gross wells under our drilling and operating agreement. Our wells will be drilled primarily in western Pennsylvania and Tennessee. Funds contributed by our participants and our managing general partner after our formation will be the only funds available to us for drilling activities, and no other wells will be drilled after this initial group. Although we estimate that 144 gross development wells will be drilled, we cannot guarantee that all of our proposed wells will be drilled or completed. Each of our proposed wells is unique and the ultimate costs incurred may be more or less than our current estimates. Our ongoing operating and maintenance costs for the next 12-month period are expected by our managing general partner to be fulfilled through revenues from the sale of our gas and oil production. Although we do not anticipate that there will be a shortfall in our revenues that we use to pay for our ongoing expenses, if one were to occur, we expect that we would borrow the necessary funds from our managing general partner or its affiliates, which are not contractually committed to make a loan. The amount we may borrow may not at any time exceed 5% of our total subscriptions and no borrowings will be obtained from third-parties. We have not and will not devote any funds to research and development activities and no new products or services will be introduced. We do not plan to sell any of our wells and intend to continue to produce them until they are depleted at which time they will be plugged and abandoned. We have no employees and rely on our managing general partner for management. CRITICAL ACCOUNTING POLICIES. The discussion and analysis of our financial condition and results of operations are based on our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of our assets, liabilities, revenues and costs and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates, including those related to oil and gas reserves and certain accrued liabilities. We base our estimates on our managing general partner's historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. 26 We have identified the following policies as critical to our business operations and understanding the results of our operations. For a detailed discussion on the application of these and other accounting policies, see Note 2 in Item 13 "Financial Statements and Supplementary Data - Notes to Financial Statements." USE OF ESTIMATES. Preparation of the financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and costs and expenses during the reporting period. Actual results could differ from these estimates. RESERVE ESTIMATES. Our estimates of our proved natural gas and oil reserves and our future net revenues from them will be based on reserve analyses that rely on various assumptions, including those required by the SEC, as to natural gas and oil prices, drilling and operating expenses, capital expenditures, abandonment costs, taxes and availability of funds. Any significant variance in these assumptions could materially affect the estimated quantity of our reserves. As a result, our estimates of our proved natural gas and oil reserves will be inherently imprecise. Actual future production, natural gas and oil prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas and oil reserves may vary substantially from our estimates or the estimates contained in the reserve reports. In addition, our proved reserves may be subject to downward or upward revision based on production history, results of future exploration and development, prevailing natural gas and oil prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control. IMPAIRMENT OF OIL AND GAS PROPERTIES. We will review our producing oil and gas properties for impairment on an annual basis and whenever events and circumstances indicate a decline in the recoverability of their carrying values. We will estimate the expected future cash flows from our oil and gas properties and compare the future cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to their fair value in the current period. The factors used to determine fair value include, but are not limited to, estimates of reserves, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that will require us to record an impairment of our oil and gas properties and impairments may be required in the future. 27 DISMANTLEMENT, RESTORATION, RECLAMATION AND ABANDONMENT COSTS. On a periodic basis, we estimate the costs of future dismantlement, restoration, reclamation and abandonment of our natural gas and oil-producing properties. We also estimate the salvage value of equipment recoverable on abandonment. We account for abandonment costs using SFAS 143, "Accounting for Asset Retirement Obligations," as discussed in Note 3 to our consolidated financial statements in Item 13 "Financial Statements and Supplementary Data - Notes to Financial Statements." As of December 31, 2005, our estimate of salvage values was greater than or equal to our estimate of the costs of future dismantlement, restoration, reclamation and abandonment. A decrease in salvage values or an increase in dismantlement, restoration, reclamation and abandonment costs from those we have estimated, or changes in our estimates or cost, could reduce our gross profit from energy operations. COMMODITY PRICE RISK. Our major market risk exposure in commodities is fluctuations in the pricing of our gas and oil production. Realized pricing is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas production. Pricing for natural gas and oil production has been volatile and unpredictable for many years. To limit our exposure to changing natural gas prices, we use hedges. Our managing general partner through its hedges seeks to provide a measure of stability in the volatile environment of natural gas prices. Our risk management objective is to lock in a range of pricing for expected production volumes. Third-party marketers to which we sell natural gas also use financial hedges to hedge their pricing exposure and make price hedging opportunities available to us. These transactions are similar to NYMEX- based futures contracts, swaps and options, but also require firm delivery of the hedged quantity. Thus, we limit these arrangements to much smaller quantities than those projected to be available at any delivery point. For the year ending December 31, 2006, we estimate in excess of 66% of our produced natural gas volumes will be sold in this manner, leaving our remaining production to be sold at contract prices in the month produced or at spot market prices. We also negotiate with certain purchasers for delivery of a portion of natural gas we will produce for the upcoming twelve months. The prices under most of our gas sales contracts are negotiated on an annual basis and are index-based. ITEM 3. PROPERTIES. DRILLING ACTIVITY. As of December 31, 2005 we had drilled 102 gross wells, which is 99.3125 net wells, and seven of these wells were online for the sale of production as shown in the following table. All of the wells we drilled were "development wells," which means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. In addition to the wells we drilled during 2005, our participants' share of our estimated drilling and equipment costs of approximately 35.375 net wells were prepaid by us in 2005. The drilling of each of the wells we prepaid in 2005 began on or before March 31, 2006, and those prepaid wells are not included in the following table. 28
DEVELOPMENT WELLS ------------------------------------------------------------------------- PRODUCTIVE (1) DRY (2) ------------------------------------ --------------------------------- GROSS (3) NET (4) GROSS (3) NET (4) ---------------- -------------- ------------- --------------- PERIOD ENDING DECEMBER 31, 2005 7 6.25 1 1
- ----------- (1) A "productive well" generally means a well that is not a dry hole. (2) A "dry hole" generally means a well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well. The term "completion" refers to the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, to the reporting of abandonment to the appropriate agency. (3) A "gross" well is a well in which we own a working interest. (4) A "net" well equals the actual working interest we own in one gross well divided by one hundred. For example, a 50% working interest in a well is one gross well, but a .50 net well. SUMMARY OF PRODUCTIVE WELLS. The table below shows the location by state and the number of productive gross and net wells in which we owned a working interest at December 31, 2005. All of our wells are classified as natural gas wells.
LOCATION GROSS NET ----- --- Pennsylvania....................................................... 7 6.25 Tennessee.......................................................... - - ----------- ------------ Total ....................................................... 7 6.25 =========== ============
PRODUCTION. The following table shows the quantities of natural gas and oil produced (net to our interest), average sales price, and average production (lifting) cost per equivalent unit of production for the period indicated.
PRODUCTION AVERAGE SALES PRICE AVERAGE PRODUCTION COST --------------------------- ------------------------ (LIFTING COST) PERIOD FROM FIRST PRODUCTION OIL (BBLS) GAS (MCF) PER BBL PER MCF (1) PER MCFE (1)(2) ---------- --------- -------- ----------- ------------------------ TO DECEMBER 31, 2005.............. - 3,100 $- $11.31 $.81
29 - ---------- (1) "Mcf" means one thousand cubic feet of natural gas. "Mcfe" means one thousand cubic feet equivalent. "Bbl" means one barrel of oil. Oil production is converted to mcfe at the rate of six mcf per barrel ("bbl"). (2) Production costs include labor to operate the wells and related equipment, repairs and maintenance, materials and supplies, property taxes, severance taxes, insurance, gathering charges and production overhead. NATURAL GAS AND OIL RESERVE INFORMATION. The following tables summarize information regarding our estimated proved natural gas and oil reserves as of the dates indicated. All of our reserves are located in the United States. We base our estimates relating to our proved natural gas and oil reserves and future net revenues of natural gas and oil reserves on internally prepared reports, which were reviewed by Wright & Company, Inc., energy consultants. In accordance with SEC guidelines, we make the SEC PV-10 estimates of future net cash flows from proved reserves using natural gas sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. We based our estimates of proved reserves on the following year-end weighted average prices. AT DECEMBER 31, 2005 Natural gas (per mcf)............................. $10.28 Oil (per bbl)..................................... $-- Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves, of necessity, are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserve reports of other engineers might differ from the reports we prepared, which were reviewed by Wright & Company, Inc., energy consultants. Results of drilling, testing and production after the date of the estimate may justify revising the estimate. Future prices received from the sale of natural gas may be different from those we estimated in preparing our reports. The amounts and timing of future operating, development and abandonment costs may also differ from those used. Thus, the reserves set forth in the following tables ultimately may not be produced and the proved undeveloped reserves may not be developed within the periods anticipated. You should not construe the estimated PV-10 values as representative of the fair market value of our proved natural gas properties. PV-10 values are based on projected cash inflows, which do not provide for changes in natural gas and oil prices or for escalation of expenses and capital costs. The meaningfulness of these estimates depends on the accuracy of the assumptions on which they were based. 30 We evaluate natural gas reserves at constant temperature and pressure. A change in either of these factors can affect the measurement of natural gas reserves. In arriving at the estimated future cash flows, we deducted when applicable the operating costs, development costs, and production-related and ad valorem taxes. We made no provision for income taxes, and based the estimates on operating methods and conditions prevailing as of the dates indicated. We cannot assure you that these estimates are accurate predictions of future net cash flows from natural gas reserves or their present value. For additional information concerning our natural gas reserves and estimates of future net revenues, see Item 13 "Financial Statements and Supplementary Data - Notes to Financial Statements."
AT DECEMBER 31, 2005 Natural gas reserves - Proved Reserves (Mcf)(1)(5): Proved developed reserves (2)...................................... 8,285,949 Proved undeveloped reserves (3).................................... - ----------- Total proved reserves of natural gas............................... 8,285,949 =========== Oil reserves - Proved Reserves (Bbl)(1)(5) Proved developed reserves (2)...................................... - Proved undeveloped reserves (3).................................... - Total proved reserves of oil....................................... - ----------- Total proved reserves (Mcfe)........................................... 8,285,949 =========== PV-10 estimate of cash flows of proved reserves (4)(5): Proved developed reserves.......................................... $34,334,917 Proved undeveloped reserves........................................ - ----------- Total PV-10 estimate $34,334,917 ===========
- ---------- (1) "Proved reserves" generally 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 by contractual arrangements, but not escalations based on future conditions. Reservoirs are considered proved if economic production is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and 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. 31 (2) "Proved developed oil and gas reserves" generally means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. (3) "Proved undeveloped reserves" generally means reserves that are expected to be recovered either from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. (4) The present value of estimated future net cash flows is calculated by discounting estimated future net cash flows by 10% annually. (5) Please see Regulation S-X rule 4-10 for complete definitions of each reserve category. We have not filed any estimates of our natural gas and oil reserves with, nor were the estimates included in any reports to, any Federal or foreign governmental agency within the 12 months before the date of this filing. For additional information concerning our natural gas and oil reserves and activities, see Item 13 "Financial Statements and Supplementary Data - Notes to Financial Statements." TITLE TO PROPERTIES. We believe that we hold good and indefeasible title to our properties in accordance with standards generally accepted in the natural gas and oil industry, subject to exceptions stated in the opinions of counsel employed by us in the various areas in which we conduct our activities. We do not believe that these exceptions detract substantially from our use of any property. As is customary in the natural gas and oil industry, we conduct only a perfunctory title examination at the time we acquire a property. Before we begin drilling operations, however, we conduct an extensive title examination and perform curative work on any defects that we deem significant. We have obtained title examinations for substantially all of our managed producing properties. No single property represents a material portion of our holdings. Our properties are subject to royalty, overriding royalty and other outstanding interests customary in the industry, such as free gas to the landowner-lessor for home heating requirements, etc. Our properties are also subject to burdens such as: o liens incident to operating agreements; o taxes; o development obligations under natural gas and oil leases; o farm-out arrangements; and 32 o other encumbrances, easements and restrictions. We do not believe that any of these burdens will materially interfere with our use of our properties. ACREAGE. The table below shows the estimated acres of developed and undeveloped natural gas and oil acreage in which we have an interest, separated by state, at December 31, 2005.
LOCATION DEVELOPED ACREAGE UNDEVELOPED ACREAGE (3) - -------- ----------------- ----------------------- GROSS (1) NET (2) GROSS (1) NET (2) --------- ------- --------- ------- Pennsylvania ........................ 2,994 2857.50 - - Tennessee ........................... 920 847.50 - - ----- -------- Total ......................... 3,914 3,705.00 - -
- ---------- (1) A "gross" acre is an acre in which we own a working interest. (2) A "net" acre equals the actual working interest we own in one gross acre divided by one hundred. For example, a 50% working interest in an acre is one gross acre, but a .50 net acre. (3) "Undeveloped acreage" means those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether or not the acreage contains proved reserves. As discussed in Item 1 "Business - Sale of Natural Gas and Oil Production," we are not required to provide any fixed and determinable quantities of natural gas under any agreement other than agreements that are the result of limited hedging agreements in the form of forward sales transactions with our natural gas purchasers. ITEM 4. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. As of December 31, 2005, we had issued 1,400 Units to 579 participants. The following table, as of December 31, 2005, sets forth the number and percentage of Units owned and held by: o beneficial owners of 5% or more of our Units; o our managing general partner's executive officers and directors; and o all of the executive officers and directors of our managing general partner as a group. The address for each director and executive officer of our managing general partner is 311 Rouser Road, Moon Township, Pennsylvania 15108. 33
UNITS -------------------------------------------- AMOUNT AND NATURE OF BENEFICIAL OWNER BENEFICIAL OWNERSHIP PERCENT OF CLASS - ---------------- ---------------------- ----------------- DIRECTORS AND EXECUTIVE OFFICERS Freddie M. Kotek................................................ 0 0% Frank P. Carolas................................................ 0 0% Jeffrey C. Simmons............................................. 0 0% Michael L. Staines.............................................. 0 0% NON-DIRECTOR EXECUTIVE OFFICERS Jack L. Hollander............................................... 0 0% Nancy J. McGurk................................................. 0 0% Michael G. Hartzell............................................. 0 0% Donald R. Laughlin.............................................. 0 0% Karen A. Black.................................................. 0 0% Marci F. Bleichmar.............................................. 0 0% All executive officers and directors as a group ................ 0 0% OTHER OWNERS OF MORE THAN 5% OF OUTSTANDING UNITS None............................................................ 0 0%
We are not aware of any arrangements which may, at a subsequent date, result in a change in our control. ITEM 5. DIRECTORS AND EXECUTIVE OFFICERS MANAGING GENERAL PARTNER. We will have no officers, directors or employees. Instead, Atlas Resources, LLC, a Pennsylvania limited liability company, which was originally formed as a corporation in 1979 and then changed to a limited liability company on March 28, 2006, will serve as our managing general partner. Our managing general partner depends on its indirect parent company, Atlas America, for management and administrative functions and financing for capital expenditures. Our managing general partner pays a management fee to Atlas America for management and administrative services, which amounted to $45.7 million, $21.6 million, and $13.1 million for our managing general partner's fiscal years ended September 30, 2005, 2004, and 2003, respectively. 34 Atlas America, Inc. recently announced that it intends to transfer into a wholly-owned limited liability company or limited partnership subsidiary of Atlas America, Inc. substantially all of its natural gas and oil exploration and production assets, and make a registered initial public offering of a minority interest, estimated to be 20%, in its newly-formed subsidiary. This Form 10 does not constitute an offer to sell or a solicitation of an offer to buy any such securities. Rather than transferring those energy assets directly to its newly-formed subsidiary, which Atlas America anticipates will be a Pennsylvania limited liability company named "Atlas Energy, LLC," Atlas America intends to make Atlas Energy, LLC the indirect owner of the energy assets by changing the Atlas America subsidiaries that currently own those assets, including our managing general partner, into limited liability company subsidiaries of Atlas Energy, LLC, and liquidating certain inactive subsidiaries of Atlas America. Atlas America anticipates that all of these transactions will be completed sometime during 2006 and before or upon the closing of the intended public offering of interests in Atlas Energy, LLC discussed above. The anticipated effect of Atlas America's intended transactions in connection with Atlas Energy, LLC can be seen by comparing the "- Current Organizational Diagram" with the "- Pro Forma Organizational Diagram (Subject to Change)" in "- Organizational Charts," below. Our managing general partner and its affiliates under Atlas America employ a total of more than 200 persons. Our managing general partner and Atlas America are headquartered at 311 Rouser Road, Moon Township, Pennsylvania 15108, near the Pittsburgh International Airport, which is also our managing general partner's primary office. In September 1998, Atlas Energy Group, Inc., the former parent company of our managing general partner, merged into Atlas America, Inc., a Delaware holding company, which was a subsidiary of Resource America, Inc., a publicly-traded company. In May 2004 Resource America conducted a public offering of a portion of its common stock (the "shares") in Atlas America. Two million six hundred forty-five thousand shares were registered and sold at a price of at $15.50 per share resulting in gross proceeds of $41 million. In May 2004, in connection with the Atlas America offering, the following officers and key employees of our managing general partner and Atlas America set forth in "- Directors, Executive Officers and Significant Employees," 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. After the public offering, Resource America continued to own approximately 80.2% of Atlas America's common stock until it distributed all of its remaining 10.7 million shares of common stock in Atlas America to its common stockholders on June 30, 2005 in the form of a spin-off by means of a tax free dividend of approximately 0.6 shares of Atlas America to Resource America common stockholders for each share of Resource America common stock owned. 35 DIRECTORS, EXECUTIVE OFFICERS AND SIGNIFICANT EMPLOYEES. The officers and directors of our managing general partner will serve until their successors are elected. The officers, directors and significant employees of our managing general partner are as follows:
NAME AGE POSITION OR OFFICE - ---- ---- ------------------ Freddie M. Kotek 50 Chairman of the Board of Directors, Chief Executive Officer and President Frank P. Carolas 46 Executive Vice President - Land and Geology and a Director Jeffrey C. Simmons 47 Executive Vice President - Operations and a Director Jack L. Hollander 50 Senior Vice President - Direct Participation Programs Nancy J. McGurk 50 Senior Vice President, Chief Financial Officer and Chief Accounting Officer Michael L. Staines 56 Senior Vice President, Secretary and a Director Michael G. Hartzell 50 Vice President - Land Administration Donald R. Laughlin 58 Vice President - Drilling and Production Marci F. Bleichmar 35 Vice President of Marketing Karen A. Black 45 Vice President - Partnership Administration Sherwood S. Lutz 55 Senior Geologist/Manager of Geology Michael W. Brecko 48 Director of Energy Sales Justin T. Atkinson 33 Director of Due Diligence Winifred C. Loncar 65 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 our 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 our managing general partner, if it is stated that they devote approximately 100% of their professional time to our 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 our managing general partner and Atlas America as compared with the other affiliates of our managing general partner, such as Viking Resources or Resource Energy. 36 FREDDIE M. KOTEK. President and Chief Executive Officer since January 2002 and Chairman of the Board of Directors since September 2001. Mr. Kotek has been Executive Vice President of Atlas America since February 2004, and served as a director from September 2001 until February 2004 and served as Chief Financial Officer from February 2004 until March 2005. Mr. Kotek was a Senior Vice President of Resource America and President of Resource Leasing, Inc. (a wholly-owned subsidiary of Resource America) from 1995 until May 2004 when he resigned from Resource America and all of its subsidiaries which are not subsidiaries of Atlas America. Mr. Kotek was President of Resource Properties from September 2000 to October 2001 and its Executive Vice President from 1993 to August 1999. Mr. Kotek 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 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 our 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 our managing general partner. Mr. Carolas is a certified petroleum geologist and has been with our 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 our 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 our managing general partner and Atlas America, and the remainder of his professional time to the business and affairs of our managing general partner's affiliates, primarily Viking Resources and Resource Energy. 37 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 our 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 devotes approximately 80% of her professional time to the business and affairs of our managing general partner and Atlas America, and the remainder of her professional time to the business and affairs of our managing general partner's affiliates. 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 devotes approximately 5% of his professional time to the business and affairs of our managing general partner and Atlas America, and the remainder of his professional time to the business and affairs of our managing general partner's affiliates, including Atlas Pipeline Partners GP. 38 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 our 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 our 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 our 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 our managing general partner and Atlas America. 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 our 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 our 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 our managing general partner and Atlas America, and the remainder of her professional time to the business and affairs of Anthem Securities. 39 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 our 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 our 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 our managing general partner and Atlas America. 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 our 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 our managing general partner and Atlas America, and the remainder of his professional time to the business and affairs of Anthem Securities. 40 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 our 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 our managing general partner and Atlas America. CODE OF BUSINESS CONDUCT AND ETHICS. Because we do not directly employ any persons, our managing general partner has determined that we will rely on a Code of Business Conduct and Ethics adopted by Atlas America, Inc. that applies to the principal executive officer, principal financial officer and principal accounting officer of our managing general partner, as well as to persons performing services for our managing general partner generally. You may obtain a copy of this code of ethics by sending a request to our managing general partner at Atlas Resources, Inc., 311 Rouser Road, Moon Township, Pennsylvania 15108. ORGANIZATIONAL CHARTS. Atlas America owns 100% of the common stock of AIC, Inc., which owns 100% of the common stock of our 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. CURRENT ORGANIZATIONAL DIAGRAM [GRAPHIC OMITTED]
------------------------------------------ Atlas America, Inc. (Delaware) (driller and operator in Ohio) (1) (4) ------------------------------------------ | | | - --------------------- -------------------- ------ -------------------- --------------- ------------- ------------- ------------ Atlas Pipeline Atlas Pipeline AIC, Atlas America, Inc. Viking Resource Atlas Noble AED Holdings, L.P. (3) Holdings GP, LLC, Inc. (Pennsylvania) Resources Energy, Inc. Corporation Investments, - --------------------- non-economic general (operating company) Corporation (2) (2) (2) Inc. partner interest in ------ ------------------- --------------- ------------- ------------- ------------ - ------------------ Atlas Pipeline Atlas Pipeline Holdings, L.P. Partners GP, LLC, -------------------- general partner interest in ------------------------- ------------------------- ------------- ------------------ Atlas Pipeline Atlas Resources, LLC, Atlas Energy Pennsylvania Anthem Partners, L.P. managing general partner Corporation, managing Industrial Securities, Inc., - ------------------ of Atlas America general partner of Energy, Inc registered Series 26-2005 L.P., exploratory drilling broker/dealer - ------------------ driller and operator partnerships and driller and Atlas Pipeline in Pennsylvania and operator dealer-manager Partners, L.P. ------------------------- -------------------------- ------------ ------------------ - ------------------ --------------------- ARD Investments, Inc. - ------------------ --------------------- Atlas Pipeline Operating Partnership, L.P. - ------------------
- -------------- (1) See "- Managing General Partner," above, for a discussion of Atlas America's stock offering in 2004. 41 (2) Viking Resources, Resource Energy, and Atlas Noble Corporation are also engaged in the oil and gas business. Atlas America manages their assets and employees including sharing common employees. Also, many of the officers and directors of our managing general partner serve as officers and directors of those entities. (3) On January 12, 2006, Atlas Pipeline Holdings, L.P., a wholly-owned subsidiary of Atlas America, filed a registration statement with the SEC for an initial public offering of 3,600,000 common units, representing an approximate 17.1% limited partner interest in it. On the successful completion of the offering, Atlas Pipeline Holdings, L.P. will own Atlas Pipeline Partners GP, LLC, which owns a 2.0% general partner interest, all the incentive distribution rights and an approximate 12.8% limited partner interest in Atlas Pipeline Partners, L.P. Atlas America will continue to own Atlas Pipeline Holdings GP, LLC, which gives Atlas America indirect general partner control over Atlas Pipeline Partners. (4) See "- Managing General Partner," above, and "- Pro Forma Organizational Diagram (Subject to Change)," below, regarding Atlas America's recent announcement that it intends to form a new subsidiary to own its natural gas and oil exploration and production assets, and conduct a public offering of a minority interest, estimated to be 20%, in the new subsidiary. This Form 10 does not constitute an offer to sell or a solicitation of an offer to buy any such securities. PRO FORMA ORGANIZATIONAL DIAGRAM (SUBJECT TO CHANGE) The following pro forma organizational diagram is subject to change, because it reflects certain transactions that Atlas America anticipates will happen in the near future, but which have not yet happened as of the date of this Form 10. The anticipated transactions set forth in the following diagram include, for example, Atlas America's formation of new wholly-owned subsidiaries Atlas Energy, LLC and Atlas Energy Manager LLC, changing many of its corporate subsidiaries to limited liability subsidiaries of Atlas Energy LLC, and liquidating certain inactive corporate subsidiaries. The changes in the following organizational diagram from the "- Current Organizational Diagram" set forth above, relate to Atlas America's recent announcement that it intends to transfer to a newly-formed subsidiary of Atlas America substantially all of its natural gas and oil exploration and production assets. Atlas America anticipates that all of these transactions will be completed before or upon the closing of Atlas Energy, LLC's public offering as described in "- Managing General Partner," above. This prospectus does not constitute an offer to sell or a solicitation of an offer to buy any such securities. 42 [GRAPHIC OMITTED]
------------------------------ Atlas America, Inc. (A Delaware corporation) (1) ------------------------------ | | - ------------------ -------------------- ----------------------- ------------------------- Atlas Pipeline Atlas Pipeline Atlas Energy, LLC (2) Atlas Energy Manager, Holdings, L.P. (3) Holdings GP, LLC, (Pennsylvania) LLC, manager of Atlas - ------------------ non-economic general ----------------------- Energy, LLC (2) partner interest in ------------------------- Atlas Pipeline - ------------------ Holdings, L.P. Atlas Pipeline --------------------- Partners GP, LLC, general partner ------------------ ----------------- ---------------- ----------------- ----------------- interest in Atlas AIC, LLC Atlas Noble, Resource Energy, Viking Resources, Atlas America, Pipeline Partners, LLC (2) LLC (2) LLC (2) LLC (2) L.P. ------------------ ----------------- ---------------- ----------------- ----------------- - ------------------ -------------- - ------------------ Atlas Energy, Atlas Pipeline LLC (2) --------------- Partners, L.P. (Ohio) REI-NY, LLC (2) - ------------------ -------------- --------------- - ------------------ ---------------- Atlas Pipeline Atlas Resources, ------------------ Operating LLC (2) Resource Well Partnership, L.P. ---------------- Services, LLC (2) - ------------------ ------------------ ------------------ Anthem Securities, Inc. ------------------
- ----------- (1) See "- Managing General Partner," above, for a discussion of Atlas America's stock offering in 2004. (2) All of these companies would be engaged in the oil and gas exploration and production business. Atlas America would continue to manage their assets and employees including sharing common employees. Also, many of the officers and directors of our managing general partner would serve as officers and directors of those entities. (3) On January 12, 2006, Atlas Pipeline Holdings, L.P., a wholly-owned subsidiary of Atlas America, filed a registration statement with the SEC for an initial public offering of 3,600,000 common units, representing an approximate 17.1% limited partner interest in it. On the successful completion of the offering, Atlas Pipeline Holdings, L.P. will own Atlas Pipeline Partners GP, LLC, which owns a 2.0% general partner interest, all the incentive distribution rights and an approximate 12.8% limited partner interest in Atlas Pipeline Partners, L.P. Atlas America will continue to own Atlas Pipeline Holdings GP, LLC, which gives Atlas America indirect general partner control over Atlas Pipeline Partners. ITEM 6. EXECUTIVE COMPENSATION. We have no employees and rely on the employees of our managing general partner and its affiliates to manage us and our business. Our managing general partner depends on its parent company, Atlas America, for management and administrative functions and financing for capital expenditures. Our managing general partner pays a management fee to Atlas America for management and administrative services, which amounted to $45.7 million, $21.6 million, and $13.1 million for its fiscal years ended September 30, 2005, 2004, and 2003, respectively. No officer or director of our managing general partner will receive any direct remuneration or other compensation from us. These persons will receive compensation solely from affiliated companies of our managing general partner. 43 ITEM 7. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. OIL AND GAS REVENUES. Our managing general partner currently is allocated 38.31% of our natural gas and oil revenues in return for paying and contributing services towards our organization and offering costs estimated to be 13% of our subscriptions, paying an estimated 74.18% of the tangible costs of our wells and contributing all of the leases covering each of our prospects on which one well is situated, for a total capital contribution estimated to be $15,903,600 . During the period ended December 31, 2005, we did not pay any cash distributions to our managing general partner or our participants. LEASES. During the period ended December 31, 2005, our managing general partner contributed undeveloped prospects (leases) to us to drill 99.3125 net wells, and received a credit to its capital account in us in the amount of $839,900. Our managing general partner anticipates entering into further lease transactions with us. ADMINISTRATIVE COSTS. Our managing general partner and its affiliates receive an unaccountable, fixed payment reimbursement from us for their administrative costs of $75 per well per month, which will be proportionately reduced if we acquire less than 100% of the working interest in a well. Our managing general partner received $400 in these fees for the period ended December 31, 2005. DIRECT COSTS. Our managing general partner and its affiliates will be reimbursed by us for all direct costs expended by them on our behalf, whether our managing general partner is acting as our managing general partner or as the operator of our wells. For the period ended December 31, 2005, we reimbursed our managing general partner $13,900 for these direct costs. DRILLING CONTRACTS. We entered into a drilling and operating agreement with our managing general partner, acting as our general drilling contractor, after our initial and final closing dates to drill and complete 134.6875 net wells. The total amount received by our managing general partner from our subscription proceeds was $34,886,500. This amount was paid by our participants for their share of the costs of drilling and completing the wells, including the wells that were prepaid in 2005, but the drilling of which was to begin on or before March 30, 2006. We have not entered into any other drilling transactions to the date of this filing, and none are anticipated by us for future periods. 44 PER WELL CHARGES. Our managing general partner, serving as operator of our wells, is reimbursed at actual cost for all direct expenses incurred on our behalf as set forth above in "- Direct Costs" and receives well supervision fees for operating and maintaining our wells during producing operations in the amount of $285 per well per month subject to annual adjustments for inflation. During the period ended December 31, 2005, our managing general partner received $1,400 for well supervision fees. GATHERING FEES. We pay a gathering fee to our managing general partner at a competitive rate for each mcf transported. For the period ended December 31, 2005, the amount paid was $400. Of this amount, 100% was paid by our managing general partner to Atlas Pipeline Partners. DEALER-MANAGER FEES. As part of the offering of our Units, our managing general partner's affiliate, Anthem Securities, Inc., serving as dealer-manager of the offering, received a 2.5% dealer-manager fee, a 7% sales commission, a 1.5% nonaccountable marketing expense fee, and a .5% accountable due diligence fee in the aggregate amount of $3,906,580. The dealer-manager will receive no further compensation from us. Of this amount, $3,139,782 was paid by Anthem Securities to third-party broker/dealers who participated in the offering of our Units. ORGANIZATION AND OFFERING COSTS. During the period ended December 31, 2005, our managing general partner paid and contributed services for our organization and offering costs in the amount of $4,535,200, including the compensation paid to the dealer-manager, which did not exceed 13% of our subscription proceeds. OTHER COMPENSATION. If our managing general partner makes a loan to us it may receive a competitive rate of interest. If our managing general partner provides equipment, supplies and other services to us, then it may do so at competitive industry rates. For the period ended December 31, 2005, no advances were made to us by our managing general partner and we did not enter into any contracts with our managing general partner for equipment, supplies and other services to us other than our partnership agreement and our drilling and operating agreement. ITEM 8. LEGAL PROCEEDINGS. None 45 ITEM 9. MARKET PRICE OF AND DIVIDENDS ON THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Currently, there is no established public trading market for our Units. As of December 31, 2005, there were no outstanding options or warrants to purchase, or securities convertible into, our Units. In addition, as of December 31, 2005, there were no Units that could be sold pursuant to Rule 144 under the Securities Act or that we have agreed to register under the Securities Act for sale by our participants and there were no Units that were being, or were publicly proposed to be, publicly offered by us. As of December 31, 2005, there were 579 holders of records of our Units. Our managing general partner reviews our accounts monthly to determine whether cash distributions are appropriate and the amount to be distributed to our managing general partner and our participants, if any. Cash distributions to our managing general partner may only be made in conjunction with distributions to our participants and only out of funds properly allocated to our managing general partner's account. We distribute those funds which our managing general partner determines are not necessary for us to retain, taking into account our managing general partner's subordination obligation as described in Item 11 "Description of Registrant's Securities to be Registered - Distributions and Subordination." We will not advance or borrow funds for purposes of distributions to our participants if the amount of the distributions would exceed our accrued and received revenues for the previous four quarters, less paid and accrued operating costs with respect to the revenues. Distributions may be reduced or deferred to the extent our 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 our direct costs; o general and administrative expenses of our managing general partner; o reserves, including a reserve for the estimated costs of eventually plugging and abandoning our wells; or o our indemnification of our managing general partner and its affiliates for losses or liabilities incurred in connection with our activities. The determination of our revenues and costs will be made in accordance with generally accepted accounting principles, consistently applied. During the period ended December 31, 2005, we made no cash distributions. ITEM 10. RECENT SALES OF UNREGISTERED SECURITIES. We sold 1,400 Units to 579 investors in a private placement offering of our Units beginning July 15, 2005 and ending August 31, 2005. Anthem Securities, Inc., an affiliate of our managing general partner, served as the dealer-manager of the offering and received the compensation set forth in Item 7 "Certain Relationships and Related Transactions - Dealer-Manager Fees." Our net proceeds from the sale of our Units were $34,886,500. 46 We relied on the exemption from registration provided by Rule 506 under Regulation D and Section 4(2) of the Securities Act in connection with the offering. Our Units were offered and sold to a limited number of persons who had the sophistication to understand the merits and risks of the investment, who had the financial ability to bear those risks, and who were "accredited investors," as that term is defined in Regulation D (17 CFR 230.501(a)). All of our participants were reasonably believed by our managing general partner to be accredited investors at the time of sale. ITEM 11. DESCRIPTION OF REGISTRANT'S SECURITIES TO BE REGISTERED. GENERAL. The rights and obligations of the holders of our Units (i.e., our participants) are governed by our partnership agreement. "Units" means both limited partner Units and investor general partner Units. The investor general partner Units will be automatically converted into limited partner Units after all of our wells have been drilled and completed. The following discussion is a summary of some of the provisions of our partnership agreement that are related to the rights and obligations associated with the Units and is qualified in its entirety by the full text of the partnership agreement. We were formed under the Delaware Revised Uniform Limited Partnership Act and are qualified to transact business in the jurisdictions where our wells are located. Our managing general partner is Atlas Resources, LLC, which has exclusive management control over all aspects of our business. In the course of its management, our managing general partner may, in its sole discretion, employ any persons, including its affiliates, as it deems necessary for our efficient operation. LIABILITY OF PARTICIPANTS FOR FURTHER CALLS AND CONVERSION. We will be governed by the Delaware Revised Uniform Limited Partnership Act. If a participant invested in us as a limited partner, then generally the participant will not be liable to third-parties for our obligations unless the participant: o also invested in us as an investor general partner; o takes part in the control of our business in addition to the exercise of a participant's rights and powers as a limited partner; or o fails to make a required capital contribution to the extent of the required capital contribution. In addition, a limited partner participant may be required to return any distribution received if the participant knew at the time the distribution was made that it was improper because it rendered us insolvent. 47 If the participant invested in us as an investor general partner for the tax benefits instead of as a limited partner, then his Units will be automatically converted by our managing general partner to limited partner Units after all of our wells have been drilled and completed. See Item 1 "Business." Currently, the conversion has not occurred, because we have not yet drilled and completed all of our wells. After the investor general partner Units are converted to limited partner Units, which is a nontaxable event, the participant will have the lesser liability of a limited partner under Delaware law for our obligations and liabilities that arise after the conversion, subject to the exceptions described above. However, an investor general partner will continue to have the responsibilities of a general partner for liabilities and obligations that we incurred before the effective date of the conversion. For example, an investor general partner might become liable for any liabilities we incurred in excess of his subscription amount during the time we engaged in drilling activities and for environmental claims that arose during drilling activities, but were not discovered until after conversion. This could result in the former investor general partner being required to make payments, in addition to his original investment, in amounts that are impossible to predict because of their uncertain nature. DISTRIBUTIONS AND SUBORDINATION. Our managing general partner will review our accounts at least monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. Subject to our managing general partner's subordination obligation as described below, our managing general partner and our participants share in all of our production revenues in the same percentage as their respective capital contribution bears to our total capital contributions, except that our managing general partner receives an additional 7% of our revenues. However, our managing general partner's total revenue share may not exceed 40% of our revenues regardless of the amount of its capital contributions to us. As of December 31, 2005, our managing general partner received 38.31% of our production revenues and our participants received 61.69% of our production revenues. Subject to the foregoing, these sharing percentages will be adjusted based on the final amount of our managing general partner's capital contributions to us after all of our wells have been drilled and completed. See our partnership agreement for special allocations between our managing general partner and our participants of equipment proceeds, lease proceeds and interest income. Our partnership agreement is structured to provide our participants with cash distributions equal to a minimum of 10% per Unit, based on $25,000 per Unit regardless of the actual subscription price paid by any participant for a Unit, in each of the first five 12-month periods beginning with our first cash distributions of revenues from operations. To help achieve this investment feature, under our partnership agreement our managing general partner will subordinate up to 50% of its share (after deducting a 1% broker/dealer participation) of our partnership net production revenues during this subordination period, which is up to 20% of our total partnership net production revenues. The term "partnership net production revenues" means our gross revenues from the sale of our natural gas and oil production from our wells after deduction of the related operating costs, direct costs, administrative costs, and all other costs not specifically allocated in the partnership agreement. If our wells produce only small natural gas and oil volumes, and/or natural gas and oil prices decrease, then even with subordination a participant may not receive the 10% return of capital for each of the first five years as described above, or a return of all of his capital during our term, because the subordination is not a guarantee. 48 Our 60-month subordination period will begin with our first cash distribution of revenues from operations in 2006. Subordination distributions will be determined by debiting or crediting our current period revenues to our managing general partner as may be necessary to provide the distributions to our participants. At any time during the subordination period our managing general partner is entitled to an additional share of our revenues to recoup previous subordination distributions to the extent cash distributions from us exceed the 10% return described above. The specific formula is set forth in Section 5.01(b)(4)(a) of our partnership agreement. PARTICIPANT ALLOCATIONS. Our participants' share as a group of our revenues, gains, income, costs, expenses, losses, and other charges and liabilities generally are charged and credited among our participants in accordance with their respective number of Units, based on $25,000 per Unit regardless of the actual subscription price paid by any participant for a Unit. These allocations also take into account any investor general partner's status as a defaulting investor general partner. Certain participants, however, paid a reduced amount to acquire their Units. Thus, our intangible drilling costs and our participants' share of our equipment costs to drill and complete our wells are charged among our participants in accordance with the respective subscription price they paid for their Units, rather than their respective number of Units. TERM, DISSOLUTION AND DISTRIBUTIONS ON LIQUIDATION. We will continue in existence for 50 years unless we are terminated earlier by a final terminating event as described below, or by an event which causes the dissolution of a limited partnership under the Delaware Revised Uniform Limited Partnership Act. However, if an event which causes our dissolution under state law is not a final terminating event, then a successor limited partnership will automatically be formed. Thus, only on a final terminating event will we be liquidated. A final terminating event is any of the following: o the election to terminate us by our managing general partner or the affirmative vote of our participants whose Units equal a majority of our total Units; o our termination under Section 708(b)(1)(A) of the Internal Revenue Code because no part of our business is being carried on; or o we cease to be a going concern. 49 On our liquidation a participant will receive his capital interest in us. Generally, this means an undivided interest in our assets, after payments to our creditors, in the ratio the participant's capital account bears to all of the capital accounts in us until all capital accounts have been reduced to zero. Thereafter, the participant's capital interest in our remaining assets will equal the participant's interest in our related revenues. Any in-kind property distributions to a participant from us must be made to a liquidating trust or similar entity, unless the participant affirmatively consents to receive an in-kind property distribution after being told the risks associated with the direct ownership of our natural gas and oil properties or there are alternative arrangements in place which assure that the participant will not be responsible for the operation or disposition of our natural gas and oil properties. If our managing general partner has not received a participant's written consent to the in-kind distribution within 30 days after it is mailed, then it will be presumed that the participant did not consent. Our 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 our managing general partner. Also, if we are liquidated our managing general partner will be repaid for any debts owed it by us before there are any distributions to our participants. TRANSFERABILITY. Our Units may not be sold, assigned or otherwise transferred unless certain conditions set forth in our partnership agreement are satisfied, including: o our managing general partner's written consent to the transfer; o an opinion of counsel acceptable to our managing general partner that the sale, assignment, pledge, hypothecation, or transfer of the Unit does not require registration and qualification under the Securities Act of 1933 and applicable state securities laws; and o a determination under the tax laws that a sale, assignment, exchange, or transfer of the Unit would not, in the opinion of our counsel, result in our termination for tax purposes or our being treated as a "publicly-traded" partnership for tax purposes. Also, under the partnership agreement transfers are subject to the following limitations: o except as provided by operation of law, we will recognize the transfer of only one or more whole Units unless the participant making the transfer owns less than a whole Unit, in which case the entire fractional interest in the Unit must be transferred; o the costs and expenses associated with the transfer must be paid by the participant transferring the Unit; o the form of transfer must be in a form satisfactory to our managing general partner; and o the terms of the transfer must not contravene those of our partnership agreement. 50 A transfer of a participant's Unit will not relieve the participant of responsibility for any obligations related to his Unit under the partnership agreement. Also, the transfer of a Unit does not grant rights under the partnership agreement, as among the transferees, to more than one party unanimously designated by the transferees to our managing general partner. Further, the transfer of a Unit does not require an accounting by our managing general partner. Any transfer when the assignee of the Unit does not become a substituted partner, as described below, will be effective as of midnight of the last day of the calendar month in which it is made or, at our managing general partner's election, 7:00 A.M. of the following day. Finally, a sale of a participant's Units could create adverse tax and economic consequences for the participant. The sale or exchange of Units held for more than 12 months generally will result in recognition of long-term capital gain or loss. However, previous deductions by the participant for depreciation, depletion and intangible drilling costs may be recaptured as ordinary income rather than capital gain, regardless of how long the participant 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. The participant's pro rata share of our liabilities, if any, as of the date of the sale or exchange must be included in the amount realized by the participant. Thus, the gain recognized by the participant may result in a tax liability greater than the cash proceeds, if any, received by the participant from the sale or other taxable disposition of his Units. Under our partnership agreement, an assignee (transferee) of a Unit may become a substituted partner only on meeting certain further conditions. The conditions to become a substituted partner are as follows: o the assignor (transferor) gives the assignee the right; o our managing general partner consents to the substitution; 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 or her agreement to be bound by all terms and provisions of the partnership agreement. A substituted partner is entitled to all of the rights of full ownership of the assigned Units, including the right to vote. We will amend our records at least once each calendar quarter to effect the substitution of substituted partners. PRESENTMENT FEATURE. Beginning in 2010 a participant may present his Units to our managing general partner for purchase. However, a participant is not required to offer his Units to our managing general partner, and may receive a greater return if the Units are retained. 51 Our managing general partner has no obligation to establish a reserve to satisfy the presentment obligation, and it does not intend to do so. Our managing general partner may immediately suspend its purchase obligation by notice to our participants if it determines, in its sole discretion, that it does not have the necessary cash flow or cannot arrange financing or other consideration for this purpose on terms it deems reasonable. Our managing general partner will not purchase less than one Unit unless the fractional Unit represents the participant's entire interest in us, nor more than 5% of our total Units in any calendar year. If fewer than all of the Units presented at any time are to be purchased, then the Units to be purchased will be selected by lot. Our managing general partner may not waive the limit on its purchasing more than 5% of our total Units in any calendar year. Our managing general partner's obligation to purchase the Units presented by our participants may be discharged for its benefit by a third-party or an affiliate of our managing general partner. The Unit will be transferred to the party who pays for it, along with the delivery of an executed assignment. The presentment must be within 120 days of our reserve report discussed below and, in accordance with Treas. Reg. ss.1.7704-1(f), the purchase may not be made by our managing general partner until at least 60 calendar days after written notice of the participant's intent to present the Unit was made. The amount of the presentment price attributable to our natural gas and oil reserves will be determined based on our last reserve report. Beginning in 2007 our managing general partner will prepare an annual reserve report of our natural gas and oil proved reserves which will be reviewed by an independent expert every year beginning in 2007. The presentment will not be considered effective until the following conditions are satisfied: o the participant receives information concerning the present worth of our future net revenues attributable to our proved reserves; o the participant agrees to the presentment price as calculated below; and o payment has been made in cash or other consideration as agreed to between our managing general partner and the participant. The presentment price to a participant will be based on his share of our net assets and liabilities as described below, based on the ratio that his number of Units bears to the total number of our Units. 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 our proved reserves determined as described above; 52 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 partnership items: o an amount equal to all debts, obligations, and other liabilities, including accrued expenses; and o any distributions made to the participant 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 our proved reserves. The amount may be further adjusted by our managing general partner for estimated changes from the date of the reserve report to the date of payment of the presentment price because of the various considerations described in our partnership agreement. VOTING RIGHTS AND AMENDMENTS. Other than as set forth below, a participant generally will not be entitled to vote on any of our partnership matters at any meeting. However, at any time participants whose Units equal 10% or more of our total Units may call a meeting to vote, or vote without a meeting, on the matters set forth below without the concurrence of our managing general partner. On the matters being voted on a participant is entitled to one vote per Unit or, if the participant owns a fractional Unit, that fraction of one vote equal to the fractional interest in the Unit. Participants whose Units equal a majority of our total Units may vote to: o dissolve us; o remove our managing general partner and elect a new managing general partner; o elect a new managing general partner if our 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 our assets; 53 o cancel any contract for services with our managing general partner, the operator, or their affiliates, which is not otherwise described in the private placement memorandum for the offering of our Units or our partnership agreement without penalty on 60 days notice; and o amend our partnership agreement; provided however, any amendment may not: o without the approval of our participants or our managing general partner, increase the duties or liabilities of the participants or our managing general partner or increase or decrease the profits or losses or required capital contribution of our participants or our managing general partner; or o without the unanimous approval of our participants, affect the classification of our income and loss for federal income tax purposes. Although our managing general partner and its officers, directors, and affiliates could have voted on certain issues as a participant if they had purchased Units, they did not purchase any Units. In addition to amendments by our participants as described above, amendments to our partnership agreement may be proposed in writing by our managing general partner and adopted with the consent of participants whose Units equal a majority of our total Units. Our partnership agreement may also be amended by our managing general partner without the consent of our participants for certain limited purposes. BOOKS AND RECORDS. Our managing general partner is required to keep true and accurate books of account of all of our financial activities in accordance with generally accepted accounting principles. A participant is permitted access to all of our records other than a list of our other participants. A participant may inspect and copy any of the records, other than a list of our participants, at any reasonable time after giving adequate notice to our managing general partner. However, our managing general partner may keep logs, well reports, and other drilling and operating data confidential for reasonable periods of time. RESTRICTIONS ON ROLL-UP TRANSACTIONS. In connection with any proposed transaction which is considered a "Roll-up Transaction" involving us and the issuance of securities of an entity (a "Roll-up Entity") that would be created or would survive after the successful completion of the Roll-up Transaction, an appraisal of all of our natural gas and oil properties must be obtained from a competent independent appraiser. Our properties must be appraised on a consistent basis, and the appraisal must be based on the evaluation of all relevant information and must indicate the value of our properties as of a date immediately before the announcement of the proposed Roll-up Transaction. The appraisal must assume an orderly liquidation of our properties over a 12-month period. The terms of the engagement of the independent appraiser must clearly state that the engagement is for the benefit of us and our participants. A summary of the appraisal, indicating all of the material assumptions underlying the appraisal, must be included in a report to our participants in connection with the proposed Roll-up Transaction. A "Roll-up Transaction" is transaction involving our acquisition, merger, conversion or consolidation, directly or indirectly, and the issuance of securities of a Roll-up Entity. This term does not include: 54 o a transaction involving our securities that have been listed on a national securities exchange or included for quotation on Nasdaq National Market System for at least 12 months; or o a transaction involving only our conversion to corporate, trust, or association form if, as a consequence of the transaction, there will be no significant adverse change in any of the following: voting rights; the term of our existence; compensation to our managing general partner; or our investment objectives. In connection with a proposed Roll-up Transaction, the person sponsoring the Roll-up Transaction must offer to our participants who vote "no" on the proposal the choice of: o accepting the securities of a Roll-up Entity offered in the proposed Roll-up Transaction; or o one of the following: o remaining as participants in us and preserving their interests in us on the same terms and conditions as existed previously, or o receiving cash in an amount equal to each participant's pro rata share of the appraised value of our net assets. We are prohibited from participating in any proposed Roll-Up Transaction: o which would result in the diminishment of any participant's voting rights under the Roll-up Entity's chartering agreement; o in which the democracy rights of our participants in the Roll-up Entity would be less than those provided for under ss.ss.4.03(c)(1) and 4.03(c)(2) of our partnership agreement or, if the Roll-up Entity is a corporation, then the democracy rights of our participants must correspond to the democracy rights provided for our participants in our partnership agreement to the greatest extent possible; o 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; 55 o in which our participants' rights of access to the records of the Roll-up Entity would be less than those provided for under ss.ss.4.03(b)(5) and 4.03(b)(6) of our partnership agreement; o in which any of the costs of the transaction would be borne by us if our participants whose Units equal a majority of our total Units do not vote to approve the proposed Roll-Up Transaction; and o unless the Roll-up Transaction is approved by our participants whose Units equal a majority of our total Units. We currently have no plans to enter into a Roll-Up Transaction. WITHDRAWAL OF MANAGING GENERAL PARTNER. After 10 years our managing general partner may voluntarily withdraw as our managing general partner for whatever reason by giving 120 days' written notice to our participants. Although our 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 our participants whose Units equal a majority of our total Units. If our participants, however, choose to terminate our existence and do not select a substitute managing general partner, then we would terminate and dissolve which could result in adverse tax and other consequences to our participants. Also, subject to a required participation of not less than 1% of our revenues, our managing general partner may withdraw a property interest from us in the form of a working interest in our wells equal to or less than its revenue interest in us without the consent of our participants. ITEM 12. INDEMNIFICATION OF DIRECTORS AND OFFICERS. Under the terms of our partnership agreement, our managing general partner, the operator, and their affiliates have limited their liability to us and our participants for any loss suffered by us or the participants 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 our best interest; o they were acting on our behalf or performing services for us; and o their course of conduct did not constitute negligence or misconduct. In addition, our partnership agreement provides for our indemnification of our managing general partner, the operator, and their affiliates against any losses, judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by them in connection with us 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 our partnership agreement purports to include indemnification for liabilities arising under the Securities Act of 1933, as amended, in the SEC's opinion this indemnification is contrary to public policy and therefore unenforceable. 56 Payments arising from the indemnification or agreement to hold harmless described above are recoverable only out of our tangible net assets, revenues, and insurance proceeds. Still, the use of our funds or assets for indemnification of our managing general partner, the operator or an affiliate would reduce amounts available for our operations or for distribution to our participants. Under our partnership agreement, we are not allowed to pay the cost of the portion of any insurance that insures our managing general partner, the operator, or an affiliate against any liability for which they cannot be indemnified as described above. However, our funds can be advanced to them for legal expenses and other costs incurred in any legal action for which indemnification is being sought if we have adequate funds available and certain conditions in our partnership agreement are met. ITEM 13. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. INDEX TO FINANCIAL STATEMENTS PAGE Report of Independent Registered Public Accounting Firm.....................58 Balance Sheet...............................................................59 Statement of Operations.....................................................60 Statement of Partners' Capital Accounts.....................................61 Statement of Cash Flows.....................................................62 Notes to Financial Statements...............................................63 57 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Partners of ATLAS AMERICA SERIES 26-2005 L.P. A DELAWARE LIMITED PARTNERSHIP We have audited the accompanying balance sheet of Atlas America Series 26-2005 L.P. (a Delaware Limited Partnership) as of December 31, 2005, and the related statement of operations, partners' capital, and cash flows for the period May 26, 2005 (date of formation) through December 31, 2005. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Atlas America Series 26-2005 L.P. as of December 31, 2005, and the results of its operations and its cash flows for the period May 26, 2005 (date of formation) through December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. /s/ Grant Thornton LLP Cleveland, Ohio March 20, 2006 (except for Note 12, as to which the date is April 28, 2006) 58 ATLAS AMERICA SERIES 26-2005 L.P. (A DELAWARE LIMITED PARTNERSHIP) BALANCE SHEET DECEMBER 31, 2005
2005 ------------- ASSETS: Current assets: Cash and cash equivalents............................................................. $ 100 Accounts receivable-affiliate......................................................... 17,251,500 ------------ Total current assets............................................................. 17,251,600 Oil and gas properties, well drilling contracts and leases, (successful efforts)....... 22,678,900 Less accumulated depletion........................................................... (7,600) ------------ 22,671,300 ------------ $ 39,922,900 ============ LIABILITIES AND PARTNERS' CAPITALS Current liabilities: Accrued liabilities................................................................... $ 13,200 ------------ Total current liabilities........................................................ 13,200 Asset retirement obligation........................................................... 567,900 Partners' capital: Managing general partner.............................................................. 4,450,900 Investor partners (1400 units)........................................................ 34,890,900 ------------ 39,341,800 ------------ $ 39,922,900 ============
The accompanying notes are an integral part of these financial statements 59 ATLAS AMERICA SERIES 26-2005 L.P. (A DELAWARE LIMITED PARTNERSHIP) STATEMENT OF OPERATIONS FOR THE PERIOD MAY 26, 2005 (DATE OF FORMATION) THROUGH DECEMBER 31, 2005
2005 ------------- REVENUES: Natural gas and oil sales................................................... $ 34,700 ------------- Total revenues........................................................ 34,700 COST AND EXPENSES: Production expenses........................................................... 2,500 Depletion of oil and gas properties........................................... 7,600 General and administrative expenses........................................... 13,600 ------------- Total expenses.......................................................... 23,700 ------------- NET EARNINGS............................................................ $ 11,000 ============= ALLOCATION OF NET EARNINGS: Managing general partner.................................................. $ 6,600 ============= Investor partners......................................................... $ 4,400 ============= Net earnings per investor partnership unit................................ $ 3 =============
The accompanying notes are an integral part of these financial statements 60 ATLAS AMERICA SERIES 26-2005 L.P. (A DELAWARE LIMITED PARTNERSHIP) STATEMENT OF PARTNERS' CAPITAL ACCOUNTS FOR THE PERIOD MAY 26, 2005 (DATE OF FORMATION) THROUGH DECEMBER 31, 2005
MANAGING GENERAL INVESTOR PARTNER PARTNERS TOTAL ------------------- ------------------- ----------------- BALANCE AT MAY 26, 2005 $ - $ - $ - Partners' capital contributions Cash.......................................................... 100 34,886,500 34,886,600 Syndication and offering costs................................ 4,535,200 - 4,535,200 Tangible equipment/leasehold costs............................ 4,444,200 - 4,444,200 --------------- --------------- --------------- Total contributions........................................... 8,979,500 34,886,500 43,866,000 Syndication and offering costs, immediately charged to capital (4,535,200) - (4,535,200) --------------- --------------- --------------- 4,444,300 34,886,500 39,330,800 Participation in revenue and costs and expenses Net production revenues....................................... 12,300 19,900 32,200 Depletion..................................................... (500) (7,100) (7,600) General and administrative.................................... (5,200) (8,400) (13,600) --------------- --------------- --------------- Net earnings.................................................. 6,600 4,400 11,000 --------------- --------------- --------------- BALANCE AT DECEMBER 31, 2005 $ 4,450,900 $ 34,890,900 $ 39,341,800 =============== =============== ===============
The accompanying notes are an integral part of these financial statements 61 ATLAS AMERICA SERIES 26-2005 L.P. (A DELAWARE LIMITED PARTNERSHIP) STATEMENT OF CASH FLOWS FOR THE PERIOD MAY 26, 2005 (DATE OF FORMATION) THROUGH DECEMBER 31, 2005
2005 ------------------ CASH FLOWS FROM OPERATING ACTIVITIES: Net earnings.................................................................................... $ 11,000 Adjustments to reconcile net earnings to net cash provided by operating activities: Depletion..................................................................................... 7,600 Increases in accrued liabilities and accounts payable affiliate............................... 13,200 Increase in accounts receivable affiliate..................................................... (17,251,500) ------------------ Net cash used in operating activities......................................................... (17,219,700) CASH FLOWS FROM INVESTING ACTIVITIES: Oil and gas well drilling contracts paid to Managing General Partner............................ (17,666,800) ------------------ Net cash used in investing activities........................................................... (17,666,800) CASH FLOWS FROM FINANCING ACTIVITIES: Partners' capital contributions................................................................. 34,886,600 ------------------ Net cash provided by financing activities 34,886,600 Net increase in cash and cash equivalents....................................................... 100 Cash and cash equivalents at beginning of period................................................ - ------------------ Cash and cash equivalents at end of period...................................................... $ 100 ================== SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES: - -------------------------------------------------------------------- Assets contributed by Managing General Partner: Tangible equipment/lease costs, included in oil and gas properties.............................. $ 4,444,200 Syndication and offering costs.................................................................. 4,535,200 ------------------ $ 8,979,400 ================== Asset retirement obligation..................................................................... $ 567,900 ==================
The accompanying notes are an integral part of these financial statements 62 ATLAS AMERICA SERIES 26-2005 L.P. (A DELAWARE LIMITED PARTNERSHIP) NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2005 NOTE 1 - NATURE OF OPERATIONS Atlas America Series 26-2005 L.P. (the "Partnership") is a Delaware Limited Partnership, which includes Atlas Resources, Inc. ("Atlas") of Pittsburgh, Pennsylvania, as Managing General Partner and Operator, and 579 subscribers to units as either Limited Partners or Investor General Partners depending upon their election. The Partnership was formed on May 26, 2005 to drill and operate gas wells located primarily in Western Pennsylvania and Tennessee. At December 31, 2005, the majority of the Partnership's properties were scheduled for drilling. Recoverability of the cost of properties is dependent on the results of such development activities. SPIN-OFF OF ATLAS AMERICA, INC. FROM RESOURCE AMERICA, INC. ("RAI"). On June 30, 2005, RAI distributed its remaining 10.7 million shares of Atlas America, Inc. to its stockholders in the form of a tax-free dividend. Although the distribution itself was tax-free to RAI's stockholders, as a result of the deconsolidation there may be some tax liability arising from prior unrelated corporate transactions among Atlas America, Inc. and some of its subsidiaries. The Partnership does not anticipate that these transactions will have a direct material impact on its financial position or results of operations. Atlas America, Inc. (and the managing general partner) no longer consolidates its federal return with RAI as of June 30, 2005. NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A summary of significant accounting policies applied in the preparation of the accompanying financial statements follows: Basis of Accounting The financial statements are prepared in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP"). Use of Estimates Preparation of the financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues, costs and expenses during the reporting period. Actual results could differ from these estimates. 63 ATLAS AMERICA SERIES 26-2005 L.P. (A DELAWARE LIMITED PARTNERSHIP) NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2005 NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Receivables In evaluating the need for an allowance for possible losses, Atlas performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customers' current creditworthiness. Atlas extends credit on an unsecured basis to many of its energy customers. At December 31, 2005, Atlas' credit evaluation indicated that it and the Partnership had no need for an allowance for possible losses. Revenue Recognition Revenues from sales of natural gas are recognized when the gas has been delivered to the purchaser. Natural gas is sold under various contracts entered into by the Partnership's managing general partner. Virtually all of the managing general partner's contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price the Partnership receives from the sale of natural gas fluctuates to remain competitive with generally available natural gas supplies in the market. Because there are timing differences between the delivery of natural gas and oil and receipt of a delivery statement, the Partnership has unbilled revenues. These revenues are accrued based on volumetric data and estimates of the related transportation and compression fees which are, in turn, based on applicable product prices. Unbilled trade receivables of $29,900 in the December 31, 2005 balance sheet are a component of "Accounts receivable - affiliate." Recently Issued Financial Accounting Standards In May 2005, the Financial Accounting Standards Board, ("FASB") issued Statement No. 154, Accounting Changes and Error Corrections ("SFAS 154"). SFAS 154 requires retrospective application to prior periods' financial statements of changes in an accounting principle. It also requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than being reported in an income statement. The statement will be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS 154 will depend on the nature and extent of any voluntary accounting changes and corrections of errors after the effective date, but management does not currently expect SFAS 154 to have a material impact on the Partnership's financial position or results of operations. Fair Value of Financial Instruments For cash, receivables and payables, the carrying amounts approximate fair values because of the short maturities of these instruments. 64 ATLAS AMERICA SERIES 26-2005 L.P. (A DELAWARE LIMITED PARTNERSHIP) NOTES TO FINANCIAL STATEMENTS (CONTINUED) DECEMBER 31, 2005 NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Supplemental Cash Flow Information The Partnership considers temporary investments with a maturity at the date of acquisition of 90 days or less to be cash equivalents. No cash was paid by the Partnership for interest or income taxes for the period ended December 31, 2005. Concentration of Credit Risk Financial instruments, which potentially subject the Partnership to concentrations of credit risk, consist principally of periodic temporary investments of cash and cash equivalents. The Partnership places its temporary cash investments in deposits with high-quality financial institutions. At December 31, 2005, the Partnership had no deposits over the insurance limit for the Federal Deposit Insurance Corporation. No losses have been experienced on such investments. Comprehensive Income The Partnership is subject to the provisions of SFAS No. 130, "Reporting Comprehensive Income," which requires disclosure of comprehensive income and its components. Comprehensive income includes net income and all other changes in equity of a business during a period from non-owner sources. These changes, other than net income, are referred to as "other comprehensive income" which includes changes in unrealized hedging gains and losses. Property and Equipment Property and equipment are stated at cost. Depletion is based on cost less estimated salvage value primarily using the unit-of-production method over the assets' estimated useful lives. Maintenance and repairs are expensed as incurred. Major renewals and improvements that extend the useful lives of property are capitalized.
Oil and gas properties consist of the following: AT DECEMBER 31, 2005 ---------------- Mineral interest in properties: Proved properties............................................. $839,900 Wells and related equipment................................... 21,839,000 ---------------- 22,678,900 Accumulated depletion: Oil and gas properties........................................ (7,600) ---------------- $ 22,671,300 ================
65 ATLAS AMERICA SERIES 26-2005 L.P. (A DELAWARE LIMITED PARTNERSHIP) NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2005 NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Oil and Gas Properties The Partnership uses 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 are capitalized. Oil is converted to gas equivalent basis ("mcfe") at the rate of one barrel equals 6 mcf. Depletion is provided on the units of production method. The Partnership's long-lived assets are reviewed for impairment annually for events or changes in circumstances that indicate that the carrying amount of an asset may not be recoverable. Long-lived assets are reviewed for potential impairments at the lowest levels for which there are identifiable cash flows that are largely independent of other groups of assets. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Partnership's plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Partnership estimates prices based upon market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. If the carrying value exceeds such cash flows, an impairment loss is recognized for the difference between the estimated fair market value (as determined by discounted future cash flows), and the carrying value of the assets. Upon the sale or retirement of a complete or partial unit of a proved property, the cost is eliminated from the property accounts, and the resultant gain or loss is reclassified to accumulated depletion. Upon the sale of an entire interest in an unproved property where the property had been assessed for impairment individually, a gain or loss is recognized in the 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. Asset Retirement Obligation The fair values of asset retirement obligations are recognized in the period they are incurred if a reasonable estimate of fair value can be made. Asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities and include costs to dismantle and relocate or dispose of production equipment, gathering systems, wells and related structures. Estimates are based on historical experience of the Partnership's managing general partner in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The Partnership does not provide for a market risk premium associated with asset retirement obligation because a reliable estimate cannot be determined. Environmental Matters The Partnership is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Partnership has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures. 66 ATLAS AMERICA SERIES 26-2005 L.P. (A DELAWARE LIMITED PARTNERSHIP) NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2005 NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) Environmental Matters (Continued) The Partnership 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 Partnership maintains insurance that may cover in whole or in part certain environmental expenditures. For the period ended December 31, 2005, the Partnership had no environmental matters requiring specific disclosure or the recording of a liability. Major Customers The Partnership's natural gas is sold under contract to various purchasers. For the period ended December 31, 2005, sales to U S Energy Exploration Corporation, Dominion Field Services, Inc., and Amerada Hess Corporation accounted for 66%, 23%, 11%, respectively of total revenues. No other customer accounted for 10% or more of total revenues for the period ended December 31, 2005. Derivative Instruments The Partnership applies the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activity" ("SFAS No. 133"). SFAS No. 133 requires each derivative instrument to be recorded in the balance sheet as either an asset or liability measured at fair value. Changes in a derivative instrument's fair value will be recognized currently in earnings unless specific hedge accounting criteria are met. NOTE 3 - ASSET RETIREMENT OBLIGATION The Partnership accounts for its estimated plugging and abandonment of its oil and gas properties in accordance with SFAS 143, "Accounting for Asset Retirement Obligations". A reconciliation of the Partnership's liability for well plugging and abandonment costs for the period ended December 31, 2005 is as follows:
2005 --------------- Asset retirement obligation, at beginning of period................. $ - Liabilities incurred from drilling wells............................ 567,900 --------------- Asset retirement obligation, at end of period....................... $ 567,900 ===============
NOTE 4 - FEDERAL INCOME TAXES The Partnership is not treated as a taxable entity for federal income tax purposes. Any item of income, gain, loss, deduction or credit flows through to the partners as though each partner had incurred such item directly. As a result, each partner must take into account his pro rata share of all items of partnership income and deductions in computing his federal income tax liability. 67 ATLAS AMERICA SERIES 26-2005 L.P. (A DELAWARE LIMITED PARTNERSHIP) NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2005 NOTE 5 - PARTICIPATION IN REVENUES AND COSTS The Managing General Partner and the other partners will generally participate in revenues and costs in the following manner:
MANAGING OTHER GENERAL PARTNER PARTNERS (3) --------------------- ------------------- Organization and offering costs............................................ 100% 0% Lease costs................................................................ 100% 0% Revenues................................................................... (1) (1) Operating costs, administrative costs, direct costs and all other costs.... (2) (2) Intangible drilling costs.................................................. 0% 100% Tangible equipment costs................................................... 74.18% 25.82%
NOTE 5 - PARTICIPATION IN REVENUES AND COSTS (CONTINUED) ------------------ (1) Subject to the Managing General Partner's subordination obligation, substantially all partnership revenues will be shared in the same percentage as capital contributions are to the total partnership capital contributions, except that the Managing General Partner will receive an additional 7% of the partnership revenues, which may not exceed 40%. (2) These costs will be charged to the partners in the same ratio as the related production revenues are credited. (3) Other Partners include both investor limited partners and investor general partners. General Partner units will automatically convert to limited partner units when all wells have been drilled and completed. Thereafter, each investor general partner will have limited liability as a limited partner under the Delaware Revised Uniform Limited Partnership Act with respect to his or her interest in the partnership. NOTE 6 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS The Partnership has entered into the following significant transactions with Atlas Resources, Inc. ("Atlas"), the Managing General Partner, and its affiliates as provided under the Partnership agreement: 68 ATLAS AMERICA SERIES 26-2005 L.P. (A DELAWARE LIMITED PARTNERSHIP) NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2005 NOTE 6 - CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS (CONTINUED) Drilling contracts to drill and complete wells for the Partnership are charged at cost plus 15%. The cost of the wells includes reimbursement to Atlas of its general and administrative overhead cost ($14,307 per well) and all ordinary and actual costs of drilling, testing and completing the wells. The Partnership paid $34,886,500 to Atlas in 2005 under the drilling contract, of which $17,666,800 had been spent as of December 31, 2005 on well drilling costs and the remaining balance of $17,219,700 is shown as part of accounts receivable-affiliate, due from Atlas, on the Partnership's balance sheet. Atlas contributed all the undeveloped leases necessary to cover each of the Partnership's prospects and received a credit to its capital account in the Partnership of $839,900. Administrative costs which are included in general and administrative expenses in the Statement of Operations are payable to Atlas at $75 per well per month. Administrative costs incurred in 2005 were $400. Monthly well supervision fees which are included in production expenses in the Statement of Operations are payable to Atlas at $285 per well per month for operating and maintaining the wells. Well supervision fees incurred in 2005 were $1,400. Transportation fees which are included in production expenses in the Statement of Operations are payable to Atlas at competitive rates in the primary and secondary drilling areas. Transportation costs incurred in 2005 were $400. The Managing General Partner and its affiliates will be reimbursed for all direct costs expended on the Partnership's behalf. For the year ended December 31, 2005, the Partnership reimbursed the Managing General Partner $13,900 for direct costs. Atlas and Anthem Securities, an affiliate of Atlas, received $4,535,200 in 2005 for fees, commissions and reimbursements as dealer-manager and to organize the Partnership. As the Managing General Partner, Atlas performs all administrative and management functions for the Partnership including billing revenues and paying expenses. Accounts receivable - affiliate on the Partnership's Balance Sheet represents the net production revenues due from Atlas. NOTE 7 - COMMITMENTS Subject to certain conditions, investor partners may present their interests beginning in 2010 for purchase by Atlas. The purchase price will be calculated by Atlas in accordance with the terms of the partnership agreement. Atlas is not obligated to purchase more than 5% of the units in any calendar year. In the event that Atlas is unable to obtain the necessary funds, Atlas may suspend its purchase obligation. 69 ATLAS AMERICA SERIES 26-2005 L.P. (A DELAWARE LIMITED PARTNERSHIP) NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2005 NOTE 7 - COMMITMENTS (CONTINUED) Beginning one year after each of the Partnership's wells has been placed into production the managing general partner, as operator, may retain $200 of the Partnership's revenues per month to cover the estimated future plugging and abandonment costs. As of December 31, 2005 the managing general partner had not withheld such funds. NOTE 8 - SUBORDINATION OF MANAGING GENERAL PARTNER'S REVENUE SHARE Under the terms of the partnership agreement, Atlas may be required to subordinate up to 50% of its share of production revenues of the Partnership, net of related operating costs, administrative costs and well supervision fees to the receipt by the investor partners of cash distributions from the Partnership equal to at least 10% of their agreed subscriptions, determined on a cumulative basis, in each of the first five years of Partnership operations, commencing with the first distribution of revenues to the investor partners. In 2005, Atlas was not required to subordinate any of its revenues to the investor Partners. NOTE 9 - DERIVATIVE INSTRUMENTS Atlas on behalf of the Partnership from time to time enters into natural gas futures and option contracts to hedge 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. Atlas formally documents all relationships between hedging instruments and the items being hedged, including Atlas'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. Atlas 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. Changes in fair value are recognized in Partners' Capital as Accumulated Other Comprehensive Income (Loss) and recognized within the statement of operations 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, Atlas will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings. At December 31, 2005, the Partnership had no open natural gas futures contracts related to natural gas sales and accordingly, had no unrealized gain or loss related to open NYMEX contracts at that date. 70 ATLAS AMERICA SERIES 26-2005 L.P. (A DELAWARE LIMITED PARTNERSHIP) NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2005 NOTE 10 - INDEMNIFICATION In order to limit the potential liability of any investor general partners, Atlas has agreed to indemnify each investor that elects to be a general partner from any liability incurred which exceeds such partner's share of Partnership assets. NOTE 11 - NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) The supplementary information summarized below presents the results of natural gas and oil activities in accordance with Statements of Financial Accounting Standards No. 69, "Disclosures About Oil and Gas Producing Activities" ("SFAS No. 69"). Annually, reserve value information is provided to the investor partners pursuant to the partnership agreement. The partnership agreement provides a presentment feature whereby the managing general partner will buy partnership units, subject to annual limitations, based upon a valuation formula price in the partnership agreement. Therefore, reserve value information under SFAS No. 69 is not presented. No consideration has been given in the following information to the income tax effect of the activities, as the Partnership is not treated as a taxable entity for income tax purposes. (1) CAPITALIZED COSTS RELATED TO OIL AND GAS PRODUCING ACTIVITIES The following table presents the capitalized costs related to natural gas and oil producing activities at December 31:
2005 -------------- Mineral interest in properties - proved properties................. $ 839,900 Wells and related equipment........................................ 21,839,000 Accumulated depletion.............................................. (7,600) ------------- NET CAPITALIZED COSTS $ 22,671,300 =============
(2) RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES The following table presents the results of operations related to natural gas and oil production for the period ended December 31:
2005 --------------- Natural gas and oil sales............................................... $ 34,700 Production costs........................................................ (2,500) Depletion............................................................... (7,600) --------------- RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES......... $ 24,600 ===============
71 ATLAS AMERICA SERIES 26-2005 L.P. (A DELAWARE LIMITED PARTNERSHIP) NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2005 NOTE 11 - NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED) (3) COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES Costs incurred for the period ended December 31, are as follows:
2005 ------------ Capitalized asset retirement obligation.................................. $ 567,900 Acquisition costs........................................................ 839,900 Tangible equipment and drilling costs.................................... 21,271,100 ------------ TOTAL COSTS INCURRED................................................. $ 22,678,900 ============
(4) OIL AND GAS RESERVE INFORMATION The information presented below represents estimates of proved natural gas and oil reserves. The estimates of the Partnership's proved gas reserves are based upon evaluations made by management and verified by Wright & Company, Inc., an independent petroleum engineering firm, as of December 31, 2005. All reserves are located within the United States. Reserves are estimated in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalation except by contractual arrangements. Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e. prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Proved developed reserves are those which are 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. All reserves are proved developed reserves and are located in the Appalachian Basin area. 72 ATLAS AMERICA SERIES 26-2005 L.P. (A DELAWARE LIMITED PARTNERSHIP) NOTES TO FINANCIAL STATEMENTS DECEMBER 31, 2005 NOTE 11 - NATURAL GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) (CONTINUED) There are numerous uncertainties inherent in estimating quantities of proved 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 Partnership's oil and gas reserves or the present value of future cash flows of equivalent reserves, due to anticipated future changes in oil and gas prices and in production and development costs and other factors for which effects have not been provided.
NATURAL GAS OIL (MCF) (BBLS) ---------- -------- Proved developed reserves: Beginning of period.................... - - Proved developed reserves.............. 8,289,000 - Production............................. (3,100) - ---------- -------- BALANCE, DECEMBER 31, 2005 8,285,900 - ========== ========
NOTE 12 - SUBSEQUENT EVENTS Atlas America, Inc. recently announced that it intends to transfer into a wholly-owned limited liability company or limited partnership subsidiary of Atlas America, Inc. substantially all of its natural gas and oil exploration and production assets. As part of that transaction, in March 2006, Atlas Resources, Inc. was merged into a newly-formed limited liability company, Atlas Resources, LLC, which Atlas America, Inc. anticipates will become an indirect subsidiary of Atlas America's newly-formed subsidiary. Atlas Resources, LLC, however, will continue to serve as the Partnership's managing general partner, and does not expect that any of these transactions will have a material effect on the Partnership's financial position or results of operations. Atlas America, Inc. further intends to make a registered initial public offering of a minority interest, estimated to be 20%, in its newly-formed subsidiary. 73 ITEM 14. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. ITEM 15. FINANCIAL STATEMENTS AND EXHIBITS (a) The following documents are filed as part of this Form 10: 1. FINANCIAL STATEMENTS The financial statements of Atlas America Series 26-2005 L.P. as of December 31, 2005 are set forth in Item 13 "Financial Statements and Supplementary Data." 2. EXHIBITS
EXHIBIT NO. DESCRIPTION ----------- ----------- 4.1 Certificate of Limited Partnership for Atlas America Series 26-2005 L.P. 4.2 Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Series 26-2005 L.P. 10.1 Drilling and Operating Agreement for Atlas America Series 26-2005 L.P. 10.2 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. 10.3 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. 10.4 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 10.5 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. 10.6 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 10.7 Base Contract for Sale and Purchase of Natural Gas dated November 13, 2002 Between UGI Energy Services, Inc. and Viking Resources Corp. 10.8 Guaranty dated June 1, 2004 between UGI Corporation and Viking Resources Corp. 10.9 Guaranty as of December 7, 2004 between FirstEnergy Corp. and Atlas Resources, Inc. 10.10 Confirmation of Gas Purchase and Sales Agreement dated November 17, 2004 between Atlas Resources, Inc. et. al. and First Energy Solutions Corp. for the period from April 1, 2006 through March 31, 2007 production/calendar periods 10.11 Transaction Confirmation dated December 14, 2004 between Atlas America, Inc. and UGI Energy Services, Inc. d/b/a GASMARK 10.12 Guaranty dated January 1, 2005 between UGI Corporation and Viking Resources Corp. 10.13 Drilling and Operating Agreement Dated September 15, 2004 by and between Atlas America, Inc. and Knox Energy, LLC 10.14 Dealer-Manager Agreement for Anthem Securities, Inc. __________________________________
74 SIGNATURES Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized. ATLAS AMERICA SERIES 26-2005 L.P. (Registrant) By: Atlas Resources, LLC Managing General Partner Date: April 28, 2006 By: /s/ Freddie Kotek --------------------------------------- Freddie Kotek, Chairman of the Board of Directors, Chief Executive Officer and President 75 EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION ----------- ----------- 4.1 Certificate of Limited Partnership for Atlas America Series 26-2005 L.P. 4.2 Amended and Restated Certificate and Agreement of Limited Partnership for Atlas America Series 26-2005 L.P. 10.1 Drilling and Operating Agreement for Atlas America Series 26-2005 L.P. 10.2 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. 10.3 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. 10.4 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 10.5 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. 10.6 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 10.7 Base Contract for Sale and Purchase of Natural Gas dated November 13, 2002 Between UGI Energy Services, Inc. and Viking Resources Corp. 10.8 Guaranty dated June 1, 2004 between UGI Corporation and Viking Resources Corp. 10.9 Guaranty as of December 7, 2004 between FirstEnergy Corp. and Atlas Resources, Inc. 10.10 Confirmation of Gas Purchase and Sales Agreement dated November 17, 2004 between Atlas Resources, Inc. et. al. and First Energy Solutions Corp. for the period from April 1, 2006 through March 31, 2007 production/calendar periods 10.11 Transaction Confirmation dated December 14, 2004 between Atlas America, Inc. and UGI Energy Services, Inc. d/b/a GASMARK 10.12 Guaranty dated January 1, 2005 between UGI Corporation and Viking Resources Corp. 10.13 Drilling and Operating Agreement Dated September 15, 2004 by and between Atlas America, Inc. and Knox Energy, LLC 10.14 Dealer-Manager Agreement for Anthem Securities, Inc. __________________________________
EX-4 2 ex4-1.txt EXHIBIT 4.1 EXHIBIT 4.1 ----------- CERTIFICATE OF LIMITED PARTNERSHIP FOR ATLAS AMERICA SERIES 26-2005 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 SERIES 26-2005 L.P.", FILED IN THIS OFFICE ON THE TWENTY-SIXTH DAY OF MAY, A.D. 2005, AT 11:30 O'CLOCK A.M. [GRAPHIC OMITTED] 3976324 8100 /s/ Harriet Smith Windsor 050439333 ----------------------------------------- Harriet Smith Windsor, Secretary of State AUTHENTICATION: 3908236 DATE: 05-26-05 State of Delaware Secretary of State Division of Corporations Delivered 11:30 AM 05/26/2005 FILED 11:30 AM 05/26/2005 SRV 050439333 - 3976324 FILEC 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 SERIES 26-2005 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 Series 26-2005 L.P. as of May 13, 2005. Partnership Name BY: ATLAS RESOURCES, INC. MANAGING GENERAL PARTNER /s/ Karen A. Black -------------------------------------------- KAREN A. BLACK, VICE PRESIDENT - PARTNERSHIP ADMINISTRATION EX-4 3 ex4-2.txt EXHIBIT 4.2 EXHIBIT 4.2 ----------- AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP FOR ATLAS AMERICA SERIES 26-2005 L.P. DATED AUGUST 25, 2005
TABLE OF CONTENTS SECTION NO. DESCRIPTION PAGE SECTION NO. DESCRIPTION PAGE I. FORMATION VII. DURATION, DISSOLUTION, AND 1.01 Formation..................................1 WINDING UP 1.02 Certificate of Limited Partnership.........1 7.01 Duration..................................47 1.03 Name, Principal Office and Residence.......1 7.02 Dissolution and Winding Up................47 1.04 Purpose....................................1 VIII. MISCELLANEOUS PROVISIONS II. DEFINITION OF TERMS 8.01 Notices...................................48 2.01 Definitions................................2 8.02 Time......................................49 8.03 Applicable Law............................49 III. SUBSCRIPTIONS AND FURTHER CAPITAL CONTRIBUTIONS 8.04 Agreement in Counterparts.................49 3.01 Designation of Managing General Partner 8.05 Amendment.................................49 and Participants.....................11 8.06 Additional Partners.......................49 3.02 Participants..............................11 8.07 Legal Effect..............................49 3.03 Subscriptions to the Partnership..........12 3.04 Capital Contributions of the Managing EXHIBITS General Partner...........................13 3.05 Payment of Subscriptions..................14 EXHIBIT (I-A) - Managing General Partner 3.06 Partnership Funds.........................14 Signature Page for Atlas America Series 26-2005 L.P. IV. CONDUCT OF OPERATIONS 4.01 Acquisition of Leases.....................15 EXHIBIT (I-B) - Subscription Agreement for 4.02 Conduct of Operations.....................17 Atlas America Series 26-2005 4.03 General Rights and Obligations of the L.P. Participants and Restricted and Prohibited Transactions...................20 EXHIBIT (II) - Drilling and Operating 4.04 Designation, Compensation and Agreement for Atlas America Removal of Managing General Series 26-2005 L.P. Partner and Removal of Operator.......28 4.05 Indemnification and Exoneration...........31 4.06 Other Activities..........................33 V. PARTICIPATION IN COSTS AND REVENUES, CAPITAL ACCOUNTS, ELECTIONS AND DISTRIBUTIONS 5.01 Participation in Costs and Revenues.......34 5.02 Capital Accounts and Allocations Thereto...............................37 5.03 Allocation of Income, Deductions and Credits...............................39 5.04 Elections.................................40 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...............................45
i These securities have not been registered under the Securities Act of 1933, as amended, or any applicable state securities acts. These securities must be acquired for investment, are restricted as to transferability, and may not be transferred or sold except in conformance with the restrictions contained in Article VI of this Amended and Restated Certificate and Agreement of Limited Partnership and in the Subscription Agreement and Annex A, Exhibit (I-B) to this Amended and Restated Certificate and Agreement of Limited Partnership. AMENDED AND RESTATED CERTIFICATE AND AGREEMENT OF LIMITED PARTNERSHIP ATLAS AMERICA SERIES 26-2005 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 August 25, 2005, 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 Series 26-2005 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 1 (ii) cause the Partnership to engage in activities outside the stated business purposes of the Partnership through joint ventures with other entities. ARTICLE II DEFINITION OF TERMS 2.01. DEFINITIONS. As used in this Agreement, the following terms shall have the meanings set forth below: 1. "Accredited Investor" means Accredited Investor, as that term is defined in Regulation D as adopted by the Securities and Exchange Commission as of the date of acceptance of the Participant's subscription. As of the date of the Private Placement Memorandum the term includes "any person who comes within any of the following categories or who the issuer reasonably believes comes within any of the following categories, at the time of the sale of the securities to that person: (i) Any bank as defined in section 3(a)(2) of the Act, or any savings and loan association or other institution as defined in section 3(a)(5)(A) of the Act whether acting in its individual or fiduciary capacity; any broker or dealer registered pursuant to section 15 of the Securities Exchange Act of 1934; any insurance company as defined in section 2(13) of the Act; any investment company registered under the Investment Company Act of 1940 or a business development company as defined in section 2(a)(48) of that Act; Small Business Investment Company licensed by the U.S. Small Business Administration under section 301(c) or (d) of the Small Business Investment Act of 1958; any plan established and maintained by a state, its political subdivisions, or any agency or instrumentality of a state or its political subdivisions for the benefit of its employees, if such plan has total assets in excess of $5,000,000; employee benefit plan within the meaning of the Employee Retirement Income Security Act of 1974 if the investment decision is made by a plan fiduciary, as defined in section 3(21) of such Act, which is either a bank, savings and loan association, insurance company, or registered investment adviser, or if the employee benefit plan has total assets in excess of $5,000,000 or, if a self-directed plan, with investment decisions made solely by persons that are accredited investors; (ii) Any private business development company as defined in section 202(a)(22) of the Investment Advisors Act of 1940; (iii) Any organization described in section 501(c)(3) of the Internal Revenue Code, corporation, Massachusetts or similar business trust, or partnership, not formed for the specific purpose of acquiring the securities offered, with total assets in excess of $5,000,000; (iv) Any director, executive officer, or general partner of the issuer of the securities being offered or sold, or any director, executive officer, or general partner of a general partner of that issuer; (v) Any natural person whose individual net worth, or joint net worth with that person's spouse, at the time of his purchase exceeds $1,000,000; (vi) Any natural person who had an individual income in excess of $200,000 in each of the two most recent years or joint income with that person's spouse in excess of $300,000 in each of those years and has a reasonable expectation of reaching the same income level in the current year; (vii) Any trust, with total assets in excess of $5,000,000, not formed for the specific purpose of acquiring the securities offered, whose purchase is directed by a sophisticated person as described in ss.230.506(b)(2)(ii); and (viii) Any entity in which all the equity owners are accredited investors." 2 2. "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. 3. "Administrator" means the official or agency administering the securities laws of a state. 4. "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. 5. "Agreement" means this Amended and Restated Certificate and Agreement of Limited Partnership, including all exhibits to this Agreement. 6. "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. 7. "Assessments" means additional amounts of capital which may be mandatorily required of or paid voluntarily by a Participant beyond his subscription commitment. 8. "Atlas" means Atlas Resources, Inc., a Pennsylvania corporation, whose principal executive offices are located at 311 Rouser Road, Moon Township, Pennsylvania 15108. 9. "Capital Account" or "account" means the account established for each party, maintained as provided in ss.5.02 and its subsections. 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. 3 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 Anthem Securities, Inc., an Affiliate of the Managing General Partner, the broker/dealer which will manage the offering and sale of the Units. 15. "Development Well" means a well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic Horizon known to be productive. 16. "Direct Costs" means all actual and necessary costs directly incurred for the benefit of the Partnership and generally attributable to the goods and services provided to the Partnership by parties other than the Sponsor or its Affiliates. Direct Costs may not include any cost otherwise classified as Organization and Offering Costs, Administrative Costs, Intangible Drilling Costs, Tangible Costs, Operating Costs or costs related to the Leases; but may include the cost of services provided by the Sponsor or its Affiliates if the services are provided pursuant to written contracts and in compliance with ss.4.03(d)(7) or pursuant to the Managing General Partner's role as Tax Matters Partner. 17. "Distribution Interest" means an undivided interest in the Partnership's assets after payments to the Partnership's creditors or the creation of a reasonable reserve therefor, in the ratio the positive balance of a party's Capital Account bears to the aggregate positive balance of the Capital Accounts of all of the parties determined after taking into account all Capital Account adjustments for the taxable year during which liquidation occurs (other than those made pursuant to liquidating distributions or restoration of deficit Capital Account balances). Provided, however, after the Capital Accounts of all of the parties have been reduced to zero, the interest in the remaining Partnership assets shall equal a party's interest in the related Partnership revenues as set forth in ss.5.01 and its subsections of this Agreement. 4 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: (i) all expenditures made for any well before production in commercial quantities for wages, fuel, repairs, hauling, supplies and other costs and expenses incident to and necessary for drilling the well and preparing the well for production of natural gas or oil, that are currently deductible pursuant to Section 263(c) of the Code and Treasury Reg. Section 1.612-4, and are generally termed "intangible drilling and development costs," (ii) the expense of plugging and abandoning any well before a completion attempt; and 5 (iii) the costs (other than Tangible Costs and Lease costs) to re-enter and deepen an existing well, complete the well to deeper reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper reservoirs. 26. "Interim Closing Date" means those date(s) after the Initial Closing Date, but before the Offering Termination Date, that the Managing General Partner, in its sole discretion, applies additional subscription proceeds to additional Partnership activities, including drilling activities. 27. "Investor General Partners" means: (i) the persons signing the Subscription Agreement as Investor General Partners; and (ii) the Managing General Partner to the extent of any optional subscription as an Investor General Partner under 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 set forth in the Private Placement Memorandum 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. 6 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 formations or reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper formations or 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. 7 39. "Participants" means: (i) the Managing General Partner to the extent of its optional subscription under ss.3.03(b)(2); (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 Series 26-2005 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. "Private Placement Memorandum" means the offering document dated July 15, 2005, as amended or supplemented from time to time, by which the Units are offered and sold. 46. "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. 47. "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. 48. "Prospect" means the drilling or spacing unit on which one Partnership well will be drilled and, if warranted, completed, which is the minimum area permitted by state law or local practice on which one well may be drilled. 49. "Proved Developed Oil and Gas Reserves" means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. 8 50. "Proved Reserves" means the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. (i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes: (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. (ii) 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. 51. "Proved Undeveloped Reserves" means reserves that are expected to be recovered from either: (i) new wells on undrilled acreage; or (ii) from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. 52. "Roll-Up" means a transaction involving the acquisition, merger, conversion or consolidation, either directly or indirectly, of the Partnership and the issuance of securities of a Roll-Up Entity. The term does not include: 9 (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: (a) the 1.5% nonaccountable due diligence fee; (b) the .5% nonaccountable marketing expense fee; (c) the 2.5% Dealer-Manager fee; and (d) payments to broker/dealers from the Managing General Partner in an amount equal to 1% of the Partnership Net Production Revenues. 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: (i) the managing and controlling general partner(s) and any other person who actually controls or selects the person who controls 25% or more of the exploratory, development or producing activities of the program, or any segment thereof, even if that person has not entered into a contract at the time of formation of the program; and (ii) whenever the context so requires, the term "sponsor" shall be deemed to include its affiliates. "Sponsor" does not include wholly independent third-parties such as attorneys, accountants, and underwriters whose only compensation is for professional services rendered in connection with the offering of units. 57. "Subscription Agreement" means an execution and subscription instrument in the form attached as Exhibit (I-B) to this Agreement, which is incorporated in this Agreement by reference. 58. "Tangible Costs" or "Capital Expenditures" means those costs associated with property acquisition and drilling and completing natural gas and oil wells which are generally accepted as capital expenditures under the Code. This includes all of the following: 10 (i) costs of equipment, parts and items of hardware used in drilling and completing a well; (ii) the costs (other than Intangible Drilling Costs and Lease costs) to re-enter and deepen an existing well, complete the well to deeper reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper reservoirs; and (iii) those items necessary to deliver acceptable natural gas and oil production to purchasers to the extent installed downstream from the wellhead of any well and which are required to be capitalized under the Code and its regulations. 59. "Tax Matters Partner" means the Managing General Partner. 60. "Units" or "Units of Participation" means Limited Partner interests and 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). 3.02(c). ADMISSION OF PARTICIPANTS. No action or consent by the Participants shall be required for the admission of additional Participants pursuant to this Agreement. All subscribers' funds shall be held in an interest-bearing account or accounts by an independent escrow holder and shall not be released to the Partnership until the receipt 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. 11 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 $25,000, except as set forth below, and shall be designated on each Participant's Subscription Agreement and payable as set forth in Section 3.05(b)(1). The minimum subscription per Participant shall be one Unit ($25,000); however, the Managing General Partner, in its discretion, may accept at any time one-half Unit ($12,500) subscriptions. Larger subscriptions shall be accepted in $1,000 increments. Notwithstanding the foregoing, the subscription price for: (i) the Managing General Partner, its officers, directors, and Affiliates, and Participants who buy Units through the officers and directors of the Managing General Partner, shall be reduced by an amount equal to the 2.5% Dealer-Manager fee, the 7% Sales Commission, the 1.5% nonaccountable marketing expense fee, and the .5% nonaccountable due diligence fee, regardless of when they subscribe, which shall not be paid with respect to these sales; and (ii) Registered Investment Advisors and their clients, and Selling Agents and their registered representatives and principals, shall be reduced by an amount equal to the 7% Sales Commission, which shall not be paid with respect to these sales. No more than 10% of the total Units 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, 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 for Units under the provisions of ss.3.03(a) and its subsections up to the minimum subscriptions which are required under ss.3.03(c)(2) for the Partnership to begin operations, 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: (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). 12 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 1,400 Units, which is up to $35,000,000 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 80 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). Pursuant to ss.3.03(b)(2), the Managing General Partner, its officers, directors, and Affiliates may purchase the number of Units required to satisfy the minimum subscription proceeds required under ss.3.03(c)(1) to the extent paid in cash and after the discounts permitted under ss.3.03(a)(1). If subscriptions for the minimum number of Units have not been received and accepted at the Offering Termination Date, then all monies deposited by subscribers shall be promptly returned to them. They shall receive interest earned on their subscription proceeds from the date the monies were deposited in escrow through the date of refund. 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: (i) the liquidation of the Partnership; or (ii) the liquidation of the Managing General Partner's interest in the Partnership. 13 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 fully vested and nonforfeitable as of the date of the formation of the Partnership and is in consideration for, and is the only consideration for, its required Capital Contributions to the Partnership. 3.05. 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 Section 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 at a rate of the greater of 6% per annum or the market rate paid by National City Bank of Pennsylvania. If the amount of interest paid by National City Bank of Pennsylvania is less than 6% per annum, then the difference shall be paid by the Managing General Partner. 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. 14 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 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 15 (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, OPERATOR 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. 16 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 17 (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; (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. 18 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. 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 at Cost plus an unaccountable, fixed payment reimbursement to the Managing General Partner of $15,000 per well for the Participants' share of the Managing General Partner's general and administrative overhead plus 15%. 4.02(d)(2). POWER OF ATTORNEY. 4.02(d)(2)(a). IN GENERAL. Each Participant appoints the Managing General Partner his true and lawful attorney-in-fact for him and in his name, place, and stead and for his use and benefit, from time to time: (i) to create, prepare, complete, execute, file, swear to, deliver, endorse, and record any and all documents, certificates, government reports, or other instruments as may be required by law, or are necessary to amend this Agreement as authorized under the terms of this Agreement, or to qualify the Partnership as a limited partnership or partnership in commendam and to conduct business under the laws of any jurisdiction in which the Managing General Partner elects to qualify the Partnership or conduct business; and (ii) to create, prepare, complete, execute, file, swear to, deliver, endorse and record any and all instruments, assignments, security agreements, financing statements, certificates, and other documents as may be necessary from time to time to implement the borrowing powers granted under this Agreement. 4.02(d)(2)(b). FURTHER ACTION. Each Participant authorizes the attorney-in-fact to take any further action which the attorney-in-fact considers necessary or advisable in connection with any of the foregoing powers and rights granted the Managing General Partner under this section and its subsections. Each party acknowledges that the power of attorney granted under Subsection 4.02(d)(2)(a): (i) is a special power of attorney coupled with an interest and is irrevocable; and (ii) shall survive the assignment by the Participant of the whole or a portion of his Units; except when the assignment is of all of the Participant's Units and the purchaser, transferee, or assignee of the Units is admitted as a successor Participant, the power of attorney shall survive the delivery of the assignment for the sole purpose of enabling the attorney-in-fact to execute, acknowledge, and file any agreement, certificate, instrument or document necessary to effect the substitution. 4.02(d)(2)(c). POWER OF ATTORNEY TO OPERATOR. The Managing General Partner is hereby authorized to grant a Power of Attorney to the Operator on behalf of the Partnership. 19 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: 20 (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 2005 calendar year, the Partnership shall provide each Participant an annual report within 120 days after the close of the calendar year, and beginning with the 2006 calendar year, a report within 75 days after the end of the first six months of its calendar year, containing unaudited financial statements of the Partnership. The reports shall include a balance sheet and statements of income, cash flow, and Partners' equity, which shall be prepared either in accordance with accounting principals followed for federal tax reporting purposes or generally accepted accounting principles which shall be determined in the discretion of the Managing General Partner. Notwithstanding the above, if the Partnership sells Units to 500 or more Participants and receives and accepts cash subscription proceeds exceeding $10 million, which the Partnership may do in the Managing General Partner's sole discretion, it must register the Units with the SEC under the Securities Exchange Act of 1934 ("Exchange Act"). This would require the Partnership to comply with the reporting requirements of the Exchange Act, including timely filing of quarterly reports on Form 10-Q, annual reports on Form 10-K and current reports on Form 8-K, and would subject the Partnership to other actions including, but not limited to, corporate governance and disclosure requirements under the Sarbanes-Oxley Act of 2002. This would increase the Partnership's Administrative Costs and Direct Costs, including legal and accounting fees, which would be paid by the Participants and the Managing General Partner as described in ss.5.01(a)(4). These additional expenses also would include the costs of required annual audited financial statements which would not otherwise be required under this Agreement. 4.03(b)(2). TAX INFORMATION. The Partnership shall, by March 15 of each year, prepare, or supervise the preparation of, and transmit to each Participant the information needed for the Participant to file the following: (i) his federal income tax return; (ii) any required state income tax return; and (iii) any other reporting or filing requirements imposed by any governmental agency or authority. 4.03(b)(3). RESERVE REPORT. Annually, beginning January 1, 2007 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; (c) basing the price of gas on the existing gas contracts; and (iii) a statement of each Participant's interest in the reserves. 21 The reserve computations shall be based on engineering reports prepared by the Managing General Partner and reviewed by an Independent Expert. 4.03(b)(4). COST OF REPORTS. The cost of all reports described in this ss.4.03(b), including the additional required reports if the Units must be registered with the SEC as described in ss.4.03(b)(1), 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 LIST. The following provisions apply regarding access to a list of Participants: (i) A current 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 purposes for which a Participant may request a copy of the Participant List only include matters relating to Participant's voting rights under this Agreement and the exercise of Participants' rights under the federal proxy laws. (iii) The Managing General Partner shall require the Participant requesting the Participant List to represent in writing that the list was not requested for a commercial purpose unrelated to the Participant's interest in the Partnership and the Participant shall pay the costs of copying the list. It shall be a defense in any action or proceeding related to the Managing General Partner's refusal to provide the Participant List to any Participant if the Managing General Partner determines that the actual purpose and reason for the Participant's 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. 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 22 (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 the period needed if, in the opinion of the Managing General Partner, the additional time is necessary to permit preparation of proxy or information statements or other documents required to be delivered in connection with the meeting by the SEC or other regulatory authorities. 4.03(c)(1)(c). MAY VOTE BY PROXY. Participants shall have the right to vote at any Participant meeting either: (i) in person; or (ii) by proxy. 4.03(c)(2). SPECIAL VOTING RIGHTS. At the request of Participants whose Units equal 10% or more of the total Units, the Managing General Partner shall call for a vote by Participants. Each Unit is entitled to one vote on all matters, and each fractional Unit is entitled to that fraction of one vote equal to the fractional interest in the Unit. Participants whose Units equal a majority of the total Units may, without the concurrence of the Managing General Partner or its Affiliates, vote to: (i) dissolve the Partnership; (ii) remove the Managing General Partner and elect a new Managing General Partner; (iii) elect a new Managing General Partner if the Managing General Partner elects to withdraw from the Partnership; (iv) remove the Operator and elect a new Operator; (v) approve or disapprove the sale of all or substantially all of the assets of the Partnership; (vi) cancel any contract for services with the Managing General Partner, the Operator, or their Affiliates that is not described in the Private Placement Memorandum or this Agreement 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 matters set forth in ss.4.03(c)(2)(ii) and (iv) above. 23 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. Each Prospect shall 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. 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, Greene County and Westmoreland County, Pennsylvania within at least 1,000 feet from a producing well, although the 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. 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. 24 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.4.03(d)(5), the Managing General Partner and its Affiliates shall not purchase any undeveloped Leases from the Partnership other than at the higher of Cost or fair market value. Farmouts to the Managing General Partner and its affiliates may be made as set forth in ss.4.03(d)(9). 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. 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). 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. 4.03(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. 25 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 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. 4.03(d)(7)(b). IF NOT DISCLOSED IN THE PRIVATE PLACEMENT MEMORANDUM 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 Private Placement Memorandum shall be set forth in a written contract which precisely describes the services to be rendered and all compensation to be paid. These contracts shall be cancelable without penalty on 60 days written notice by Participants whose Units equal a majority of the total Units. 4.03(d)(8). LOANS. 4.03(d)(8)(a). NO LOANS FROM THE PARTNERSHIP. No loans or advances shall be made by the Partnership to the Managing General Partner or 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 may Farmout an undeveloped lease or well activity to the Managing General Partner, its Affiliates, or unaffiliated third-parties only if the Managing General Partner, exercising the standard of a prudent operator, determines that: (i) the Partnership lacks the funds to complete the oil and gas operations on the Lease or well and cannot obtain suitable financing; (ii) drilling on the Lease or the intended well activity would concentrate excessive funds in one location, creating undue risks to the Partnership; (iii) the Leases or well activity have been downgraded by events occurring after assignment to the Partnership so that development of the Leases or well activity would not be desirable; or (iv) the best interests of the Partnership would be served. If the Partnership Farmouts a Lease or well activity, the Managing General Partner must retain on behalf of the Partnership the economic interests and concessions as a reasonably prudent oil and gas operator would or could retain under the circumstances prevailing at the time, consistent with industry practices. 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. 26 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 with respect to the drilling contracts. 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. 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 27 (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 which would operate to materially impede or frustrate the accumulation of shares by any purchaser of the securities of the Roll-Up Entity, except to the minimum extent necessary to preserve the tax status of the Roll-Up Entity. The Partnership shall not participate in any proposed Roll-Up transaction which would limit the ability of a Participant to exercise the voting rights of its securities of the Roll-Up Entity on the basis of the number of Units held by that Participant. 4.03(d)(16)(e). NO ROLL-UP IF ACCESS TO RECORDS WOULD BE LIMITED. The Partnership shall not participate in a Roll-Up in which Participants' rights of access to the records of the Roll-Up Entity would be less than those provided for under ss.ss.4.03(b)(5) and 4.03(b)(6). 4.03(d)(16)(f). COST OF ROLL-UP. The Partnership shall not participate in any proposed Roll-Up transaction in which any of the costs of the transaction would be borne by the Partnership if Participants whose Units equal a majority of the total Units do not vote to approve the proposed Roll-Up. 4.03(d)(16)(g). ROLL-UP APPROVAL. The Partnership shall not participate in a Roll-Up transaction unless the Roll-Up transaction is approved by Participants whose Units equal a majority of the total Units. 4.03(d)(17). DISCLOSURE OF BINDING AGREEMENTS. Any agreement or arrangement which binds the Partnership must be disclosed in the Private Placement Memorandum. 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: (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 28 (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 be proportionately reduced to the extent the Partnership acquires less than 100% of the Working Interest in the well; and (ii) 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 natural 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 natural gas production is gathered and transported 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 and transporting the natural gas. If the Partnership's natural gas production is gathered and transported through a gathering system owned by the Managing General Partner or its Affiliates other than Atlas Pipeline Partners, then the Managing General Partner or its Affiliates shall receive, or retain in the case of the Managing General Partner, the gathering fee paid to the Managing General Partner. Also, in the Mississippian and Devonian Shale Reservoirs in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee, if the Coalfield Pipeline does not have sufficient capacity to compress and transfer the natural gas produced from the Partnership's wells as determined by Atlas America, then Atlas America or an Affiliate other than Atlas Pipeline Partners may construct an additional gathering system and/or enhancements to the Coalfield Pipeline. On completion of the construction, Atlas America will transfer its ownership in the additional gathering system and/or enhancements to the owners of the Coalfield Pipeline, which will then pay Atlas America an amount equal to $.12 per mcf of natural gas transported through the newly constructed and/or enhanced gathering system. Coalfield Pipeline will charge this $.12 per mcf to the Partnership in addition to the rate that it is charging at that time. As of the date of the Private Placement Memorandum, Coalfield Pipeline was charging $.55 per mcf for transportation plus fees for compression. 4.04(a)(2)(e). DEALER-MANAGER FEE. Subject to ss.3.03(a)(1), the Dealer-Manager shall receive on each Unit sold: (i) a 2.5% Dealer-Manager fee; (ii) a 7% Sales Commission; (iii) a 1.5% nonaccountable marketing expense fee; and (iv) a .5% nonaccountable due diligence fee. Finally, as an additional incentive, to the extent permitted by applicable law, all Selling Agents and the Dealer-Manager that have one or more registered representatives and/or principals who sell at least six Units (including Units sold at discounted prices) each shall share in payments from the Managing General Partner in an amount equal to 1% of the Partnership Net Production Revenues. A qualifying broker/dealer's participation in these payments shall be in the ratio which the total amount of Units sold by all of its registered representatives and/or principals who sell at least six Units each bears to the total amount of Units sold by all registered representatives and/or principals who sell at least six Units each. 29 4.04(a)(2)(f). DRILLING AND OPERATING AGREEMENT. The Managing General Partner and its Affiliates shall receive compensation as set forth in the Drilling and Operating Agreement. 4.04(a)(2)(g). OTHER TRANSACTIONS. The Managing General Partner and its Affiliates may enter into transactions pursuant to 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 to calculate the presentment price in the most recent presentment offer under ss.6.04, 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. At the time of its removal the removed Managing General Partner shall cause, to the extent it is legally possible, its successor to be transferred or assigned all its rights, obligations and interests as Managing General Partner of the Partnership in contracts entered into by it on behalf of the Partnership. In any event, the removed Managing General Partner shall cause its rights, obligations and interests as Managing General Partner of the Partnership in any such contract to terminate at the time of its removal. 30 Notwithstanding any other provision in this Agreement, the Partnership or the successor Managing General Partner shall not: (i) be a party to any natural gas supply agreement that the Managing General Partner or its Affiliates enters into with a third-party; (ii) have any rights pursuant to such natural gas supply agreement; or (iii) receive any interest in the Managing General Partner's and its Affiliates' 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 31 (iii) the course of conduct did not constitute negligence or misconduct of the Managing General Partner, the Operator, or their Affiliates. 4.05(a)(2). STANDARDS FOR MANAGING GENERAL PARTNER INDEMNIFICATION. The Managing General Partner, the Operator, and their Affiliates shall be indemnified by the Partnership against any losses, judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by them in connection with the Partnership, provided that: (i) the Managing General Partner, the Operator, and their Affiliates determined in good faith that the course of conduct which caused the loss or liability was in the best interest of the Partnership; (ii) the Managing General Partner, the Operator, and their Affiliates were acting on behalf of, or performing services for, the Partnership; and (iii) the course of conduct was not the result of negligence or misconduct of the Managing General Partner, the Operator, or their Affiliates. Provided, however, payments arising from such indemnification or agreement to hold harmless are recoverable only out of the following: (i) the Partnership's tangible net assets, which includes revenues from operations; and (ii) any insurance proceeds received by the Partnership. 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 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. 32 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. 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, or 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; 33 (ii) reserve partial interests in Leases being assigned to the Partnership or any other interests not expressly prohibited by this Agreement; (iii) deal with the Partnership as independent parties or through any other entity in which they may be interested; (iv) conduct business with the Partnership as set forth in this Agreement; and (v) participate in such other investor operations, as investors or otherwise. The Managing General Partner and its Affiliates shall not be required to permit the Partnership or the Participants to participate in 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. 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. Ninety percent (90%) of the Partnership's subscription proceeds received from the Participants shall be used to pay 100% of the Intangible Drilling Costs. 5.01(a)(3). TANGIBLE COSTS. Ten percent (10%) of the Partnership's subscription proceeds received from the Participants shall be used by the Partnership to pay Tangible Costs. All remaining Tangible Costs in excess of an amount equal to 10% of the Partnership's subscription proceeds shall be charged 100% to the Managing General Partner. 5.01(a)(4). OPERATING COSTS, DIRECT COSTS, ADMINISTRATIVE COSTS AND ALL OTHER COSTS. Operating Costs, Direct Costs, Administrative Costs, and all other Partnership costs not specifically allocated shall be charged to the parties in the same ratio as the related production revenues are being credited. 34 5.01(a)(5). ALLOCATION OF INTANGIBLE DRILLING COSTS AND TANGIBLE COSTS AT PARTNERSHIP CLOSINGS. Intangible Drilling Costs and the Participants' share of Tangible Costs of a well or wells to be drilled and completed with the proceeds of a Partnership closing shall be charged 100% to the Participants who are admitted to the Partnership in that closing and shall not be reallocated to take into account other Partnership closings. Although the proceeds of each Partnership closing will be used to pay the costs of drilling different wells, 90% of each Participant's subscription proceeds shall be applied to Intangible Drilling Costs and 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 40% 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 35% of the total Partnership Capital Contributions and the Participants contribute 65% of the total Partnership Capital Contributions, then the Managing General Partner shall receive 40% of the Partnership revenues, not 42%, because its revenue share cannot exceed 40% of Partnership revenues, and the Participants shall receive 60% of Partnership revenues. 35 5.01(b)(4)(a). SUBORDINATION. The Managing General Partner shall subordinate up to 50% of its share of Partnership Net Production Revenues (after deducting the 1% broker/dealer participation) to the receipt by Participants of cash distributions from the Partnership equal to $2,500 (10%) per Unit, based on $25,000 per Unit, regardless of the actual subscription price paid by the Participants for their Units, in each of the first five 12-month periods. In this regard: (i) the 60-month subordination period shall begin with the first cash distribution from operations to the Participants; (ii) subsequent subordination distributions, if any, shall be determined and made at the time of each subsequent distribution of revenues to the Participants; and (iii) the Managing General Partner shall not subordinate more than 50% of its share of Partnership Net Production Revenues in any 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) $2,500 per Unit (10% per Unit) in the first 12-month period; (b) $5,000 per Unit (20% per Unit) in the second 12-month period; (c) $7,500 per Unit (30% per Unit) in the third 12-month period; or (d) $10,000 per Unit (40% per Unit) in the fourth 12-month period (no carry forward is required if such distributions are less than $12,500 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) $2,500 per Unit (10% per Unit) in the first 12-month period; (b) $5,000 per Unit (20% per Unit) in the second 12-month period; (c) $7,500 per Unit (30% per Unit) in the third 12-month period; (d) $10,000 per Unit (40% per Unit) in the fourth 12-month period; or (e) $12,500 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 monthly distribution, the Managing General Partner will not have any subordination obligation if the distributions to Participants equal $208.33 per Unit (8.33% of $2,500 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; 36 (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 (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 $25,000 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, allocating any item of income, gain, loss, deduction or credit which is not otherwise specifically allocated in this Agreement or is clearly inconsistent with a party's economic interest in the Partnership, or making any other allocations under this Agreement, the Managing General Partner may adopt any method of allocation which it, in its reasonable discretion, selects in its sole discretion, after consultation with the Partnership's legal counsel or accountants. Any new allocation provisions shall be made in a manner that is consistent with the parties' economic interests in the Partnership and which 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; 37 (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); 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. Also, in the event, and to the extent, that the Managing General Partner is treated under the Code as having been transferred an interest in the Partnership in connection with the performance of services for the Partnership (whether before or after the formation of the Partnership): (i) any resulting compensation income shall be allocated 100% to the Managing General Partner; (ii) any associated increase in Capital Accounts shall be credited 100% to the Managing General Partner; and (iii) any associated deduction to which the Partnership is entitled shall be allocated 100% to the Managing General Partner. 5.02(d). DISCRETION OF MANAGING GENERAL PARTNER IN THE METHOD OF MAINTAINING CAPITAL ACCOUNTS. Notwithstanding any other provisions of this Agreement, the method of maintaining Capital Accounts may be changed from time to time, in the discretion of the Managing General Partner, to take into consideration 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). 38 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. 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. If a Partnership expenditure, whether or not deductible, that gives rise to a tax credit in a Partnership taxable year also gives rise to valid allocations of Partnership loss or deduction, or other downward Capital Account adjustments, for the year, then the parties' interests in the Partnership with respect to the credit, or the cost giving rise thereto, shall be in the same proportion as the parties' respective distributive shares of the loss or deduction, and adjustments. If Partnership receipts, whether or not taxable, that give rise to a tax credit, including a marginal well production credit under ss.45I of the Code, in a Partnership taxable year also give rise to valid allocations of Partnership income or gain, or other upward Capital Account adjustments, for the year, then the parties' interests in the Partnership with respect to the credit, or the Partnership's receipts or production of natural gas and oil production giving rise thereto, shall be in the same proportion as the parties' respective shares of the Partnership's production revenues from the sales of its natural gas and oil production as provided in ss.5.01(b)(4). 39 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. 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 the Code, including Subchapter K of Chapter 1 of Subtitle A of the Code. 40 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. 5.04(e). SS.83 ELECTION. The Partnership, the Managing General Partner and each Participant hereby agree to be legally bound by the provisions of this ss.5.04(e) and further agree that, in the Managing General Partner's sole discretion, the Partnership and all of its Partners may elect a safe harbor under which the fair market value of a Partnership interest that is transferred in connection with the performance of services is treated as being equal to the liquidation value of that interest for transfers on or after the date final regulations providing the safe harbor are published in the Federal Register. If the Managing General Partner determines to elect the safe harbor on behalf of the Partnership and all of its Partners, which determination may be made solely in the best interests of the Managing General Partner, the Partnership, the Managing General Partner and each Participant further agree that: (i) the Partnership shall be authorized and directed to elect the safe harbor; (ii) the Partnership and each of its Partners (including any Person to whom a Partnership interest is transferred in connection with the performance of services) shall comply with all requirements of the safe harbor with respect to all Partnership interests transferred in connection with the performance of services while the election remains effective; and (iii) the Managing General Partner, in its sole discretion, may cause the Partnership to terminate the safe harbor election, which determination may be made in the sole interests of the Managing General Partner. 5.05. DISTRIBUTIONS. 5.05(a). IN GENERAL. 5.05(a)(1). MONTHLY REVIEW OF ACCOUNTS. The Managing General Partner shall review the accounts of the Partnership at least monthly to determine whether cash distributions are appropriate and the amount to be distributed, if any. 5.05(a)(2). DISTRIBUTIONS. 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. 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. 41 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. 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. Except as otherwise provided in this Agreement, no party shall under any circumstances be entitled to any interest on amounts retained by the Partnership. Each Participant shall look only to his share of distributions, if any, from the Partnership for a return of his Capital Contribution. ARTICLE VI TRANSFER OF INTERESTS 6.01. TRANSFERABILITY. 6.01(a). IN GENERAL. 6.01(a)(1). CONSENT REQUIRED. In addition to other restrictions on transferability provided in this Agreement, Units shall be nontransferable except transfers to or with the written consent of the Managing General Partner. 6.01(a)(2). 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 unless there is either: (i) an effective registration of the Unit under the Securities Act of 1933, as amended, and qualification under applicable state securities laws; or (ii) an opinion of counsel acceptable to the Managing General Partner that the registration and qualification of the Unit is not required. Transfers are also subject to any conditions contained in the Subscription Agreement and Annex A to the Subscription Agreement. 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; 43 (ii) the Managing General Partner consents to the substitution, which shall be in the Managing General Partner's absolute discretion; (iii) the assignee pays to the Partnership all costs and expenses incurred in connection with the substitution; and (iv) 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. 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 Wells equal to or less than its respective interest in the revenues of the Partnership without the consent of the Participants. 44 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. 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 in 2010 subject to the following conditions: (i) the presentment must be made within 120 days of the reserve report set forth in ss.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 or other consideration 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: 45 (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. 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 or arrange other consideration 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. 46 ARTICLE VII DURATION, DISSOLUTION, AND WINDING UP 7.01. DURATION. 7.01(a). FIFTY YEAR TERM. The Partnership shall continue in existence for a term of 50 years from the effective date of this Agreement unless sooner terminated as set forth below. 7.01(b). TERMINATION. The Partnership shall terminate following the occurrence of: (i) a Final Terminating Event; or (ii) any event 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 partnership and the parties to the successor limited partnership. 7.02. DISSOLUTION AND WINDING UP. 7.02(a). FINAL TERMINATING EVENT. On the occurrence of a Final Terminating Event the affairs of the Partnership shall be wound up and there shall be distributed to each of the parties its Distribution Interest in the remaining Partnership assets. 7.02(b). TIME OF LIQUIDATING DISTRIBUTION. To the extent practicable and in accordance with sound business practices in the judgment of the Managing General Partner, liquidating distributions shall be made by: (i) the end of the taxable year in which liquidation occurs, determined without regard to 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. 47 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: (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. 48 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. 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: (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; (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; or (iv) cure any ambiguity, correct or supplement any provision in this Agreement that may be inconsistent with any other provision in this Agreement, or add any other provision to this Agreement with respect to matters, events or issues arising under this Agreement that is not inconsistent with the provisions of this Agreement. 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: /s/ Frank P. Carolas Frank P. Carolas, EVP 49 EX-10 4 ex10-1.txt EXHIBIT 10.1 EXHIBIT 10.1 ------------ DRILLING AND OPERATING AGREEMENT FOR ATLAS AMERICA SERIES 26-2005 L.P. DATED AUGUST 25, 2005
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................................................11 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.............................................................................15 16. Waiver of Default or Breach................................................................................15 17. Notices....................................................................................................15 18. Interpretation.............................................................................................15 19. Counterparts...............................................................................................15 Signature Page.............................................................................................16 Exhibit A Description of Leases and Initial Well Locations Exhibits A-l through A-9 Maps of Initial Well Locations Exhibit B Form of Assignment Exhibit C Form of Addendum
i DRILLING AND OPERATING AGREEMENT THIS AGREEMENT made this 25th day of August 2005, by and between ATLAS RESOURCES, INC., a Pennsylvania corporation (hereinafter referred to as "Atlas" or "Operator"), and ATLAS AMERICA SERIES 26-2005 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 nine (9.0) 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-9; 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 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-9. The amount of acreage included in each Additional Well Location and the configuration of the Additional Well Location shall be indicated on the maps to be attached as exhibits to the applicable addendum to this Agreement as provided in sub-section (c) below. (b) REPRESENTATIONS AND INDEMNIFICATION ASSOCIATED WITH THE ASSIGNMENT OF THE LEASE. The Operator represents and warrants to the Developer that: (i) the Operator is the lawful owner of the Lease and rights and interest under the Lease and of the personal property on the Lease or used in connection with the Lease; (ii) the Operator has good right and authority to sell and convey the rights, interest, and property; (iii) the rights, interest, and property are free and clear from all liens and encumbrances; and (iv) all rentals and royalties due and payable under the Lease have been duly paid. These representations and warranties shall also be included in each recorded assignment of the acreage included in each Initial Well Location and Additional Well Location designated pursuant to sub-section (c) below, substantially in the manner set forth in Exhibit B. 1 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 nine (9) oil and gas wells on the nine (9) 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 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. (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. 2 (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; (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; 3 (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. Each oil and gas well which is drilled and completed under this Agreement shall be drilled and completed on a Cost plus an unaccountable, fixed payment reimbursement of $15,000 per well for the share of Operator's general and administrative overhead charged by Developer to its Participants 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: (i) all expenditures made with respect to any well before the establishment of production in commercial quantities for wages, fuel, repairs, hauling, supplies and other costs and expenses incident to and necessary for the drilling of the well and the preparation of the well for the production of oil or gas, that are currently deductible pursuant to Section 263(c) of the Internal Revenue Code of 1986, as amended, (the "Code"), and Treasury Reg. Section 1.612-4, which are generally termed "intangible drilling and development costs"; (ii) the expense of plugging and abandoning any well before a completion attempt; and (iii) the costs (other than Tangible Costs and Lease costs) to re-enter and deepen an existing well, complete the well to deeper formations or reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper formations or reservoirs. "Tangible Costs" shall mean those costs associated with property acquisition and the drilling and completion of oil and gas wells which are generally accepted as capital expenditures pursuant to the provisions of the Code. This includes: (i) all costs of equipment, parts and items of hardware used in drilling and completing a well; (ii) the costs (other than Intangible Drilling Costs and Lease costs) to re-enter and deepen an existing well, complete the well to deeper formations or reservoirs, or plug and abandon the well if it is nonproductive from the targeted deeper formations or reservoirs; and (iii) those items necessary to deliver acceptable oil and gas production to purchasers to the extent installed downstream from the wellhead of any well 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. 5 Developer shall pay, in proportion to the share of the Working Interest owned by the Developer in the wells, any extra costs incurred for each well pursuant to sub-section (a) above within ten (10) business days of its receipt of Operator's statement for the extra costs. (c) COMPLETION DETERMINATION. Operator shall determine whether or not to run the production casing for an attempted completion or to plug and abandon any well drilled under this Agreement. However, a well shall be completed only if Operator has made a good faith determination that there is a reasonable possibility of obtaining commercial quantities of oil and/or gas. (d) DRY HOLE DETERMINATION. If Operator determines at any time during the drilling or attempted completion of any well 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 completed 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 6 (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: (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 completed 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. 7 If a third-party serves as the actual operator of the well, then this fee shall be $25 above the actual third-party operator's monthly charges. The $25 will be retained by Operator each month for reviewing the costs and expenses charged by the third-party operator and monitoring the third-party operator's accounting and production records for the well on behalf of the Developer. The operating fees shall cover all normal, regularly recurring operating expenses for the production, delivery and sale of natural gas, including without limitation: (i) well tending, routine maintenance and adjustment; (ii) reading meters, recording production, pumping, maintaining appropriate books and records; (iii) preparing reports to the Developer and government agencies; and (iv) collecting and disbursing revenues. The operating fees shall not cover costs and expenses related to the following: (i) the production and sale of oil; (ii) the collection and disposal of salt water or other liquids produced by the wells; (iii) the rebuilding of access roads; and (iv) the purchase of equipment, materials or third party services; which, subject to the provisions of sub-section (c) of this Section 6, shall be 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. 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. 8 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. 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 of 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. 9 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. (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 or marginal well production tax credit, if applicable. (e) ADDITIONAL INFORMATION. Operator shall promptly furnish the Developer with any additional information as it may reasonably request, including without limitation geological, technical, and financial information, in the form as may reasonably be requested, pertaining to any phase of the operations and activities governed by this Agreement. The Developer and its authorized employees, agents and consultants, including independent accountants shall, at Developer's sole cost and expense: 10 (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: (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. 11 (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: (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. 12 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: (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 Subtitle A of the Internal Revenue Code of 1986, as amended. If the income tax laws of the state or states in which the property covered by this Agreement is located contain, or may subsequently contain, a similar election, each of the parties agrees that the election shall be exercised. Beginning with the first taxable year of operations under this Agreement, each party agrees that the deemed election provided by Section 1.761-2(b)(2)(ii) of the Regulations under the Internal Revenue Code of 1986, as amended, will apply; and no party will file an application under Section 1.761-2 (b)(3)(i) 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. 13 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. 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 in 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, the inability of Operator to begin the drilling of the wells subject to this Agreement by the applicable times set forth in Section 2(b) or in any Addendum to this Agreement due to decisions of third-party operators to delay drilling the wells, poor weather conditions, inability to obtain drilling permits, access 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. 14 15. INTEGRATION; WRITTEN AMENDMENT. (a) INTEGRATION. This Agreement, including the Exhibits to this Agreement, constitutes and represents the entire understanding and agreement of the parties with respect to the subject matter of this Agreement and supersedes all prior negotiations, understandings, agreements, and representations relating to the subject matter of this Agreement. (b) WRITTEN AMENDMENT. No change, waiver, modification, or amendment of this Agreement shall be binding or of any effect unless in writing duly signed by the party against which the change, waiver, modification, or amendment is sought to be enforced. 16. WAIVER OF DEFAULT OR BREACH. No waiver by any party to any default of or breach by any other party under this Agreement shall operate as a waiver of any future default or breach, whether of like or different character or nature. 17. NOTICES. Unless otherwise provided in this Agreement, all notices, statements, requests, or demands 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 Series 26-2005 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. 15 IN WITNESS WHEREOF, the parties hereto have duly executed this Agreement as of the day and year first above written. ATLAS RESOURCES, INC. By: /s/ Frank P. Carolas Frank P. Carolas, Executive Vice President ATLAS AMERICA SERIES 26-2005 L.P. By its Managing General Partner: ATLAS RESOURCES, INC. By: /s/ Frank P. Carolas Frank P. Carolas, Executive Vice President 16 DESCRIPTION OF LEASES AND INITIAL WELL LOCATIONS [To be completed as information becomes available] 1. WELL LOCATION (a) Oil and Gas Lease from ______________________________________ dated _____________________ and recorded in Deed Book Volume __________, Page __________ in the Recorder's Office of County, ____________, covering approximately _________ acres in ____________________________ Township, ___________________ County, __________________________. (b) The portion of the leasehold estate constituting the ____________________________________________ No. __________ Well Location is described on the map attached hereto as Exhibit A-l. (c) Title Opinion of _________________________________, ____________________ ________________, ________________________________________, ____________ ____________________________, dated ___________________, 200___. (d) The Developer's interest in the leasehold estate constituting this Well Location is an undivided % Working Interest to those oil and gas rights from the surface to the bottom of the __________________ Formation, subject to the landowner's royalty interest and overriding royalty interests. Exhibit A (Page 1) Well Name, Twp. County, State ASSIGNMENT OF OIL AND GAS LEASE STATE OF _______________________________ COUNTY OF _____________________________ KNOW ALL MEN BY THESE PRESENTS: THAT the undersigned _____________ (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 SERIES 26-2005 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 before the close of the 90th day after the close of the calendar year in which this Addendum is entered into by Operator and the Developer. 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 SERIES 26-2005 L.P. By its Managing General Partner: ATLAS RESOURCES, INC. By ________________________________ Exhibit C (Page 2)
EXHIBIT A DRILLING AND OPERATING AGREEMENT DATED AUGUST 25, 2005 ATLAS AMERICA SERIES 26-2005 L.P. WELL STATE COUNTY TOWNSHIP - ------------------------------------------ --------------- ---------------------------- ------------------------------------- EGLINTON #1 PA CRAWFORD VERNON SMITH #11 PA CRAWFORD HAYFIELD DILLAMAN #3 PA CRAWFORD HAYFIELD SKUFKA #2 PA FAYETTE PERRY TRIPLETT #6 PA FAYETTE NICHOLSON CHRISTOPHER #4 PA FAYETTE GERMAN BR-1029 TN SCOTT FORK MOUNTAIN FIELD BR-1030 TN SCOTT FORK MOUNTAIN FIELD BR-1032 TN SCOTT FORK MOUNTAIN FIELD
EX-10.2 5 ex10-2.txt EXHIBIT 10.2 EXHIBIT 10.2 ------------ 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-10.3 6 ex10-3.txt EXHIBIT 10.3 Exhibit 10.3 ------------ 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. /s/ Randy Scilla ----------------------- Randy Scilla Assistant Treasurer 3 EX-10.4 7 ex10-4.txt EXHIBIT 10.4 EXHIBIT 10.4 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-10.5 8 ex10-5.txt EXHIBIT 10.5 EXHIBIT 10.5 ------------ 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-10.6 9 ex10-6.txt EXHIBIT 10.6 EXHIBIT 10.6 ------------ 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-10.7 10 ex10-7.txt EXHIBIT 10.7 Exhibit 10.7 ------------ 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-10.8 11 ex10-8.txt EXHIBIT 10.8 EXHIBIT 10.8 GUARANTY DATED JUNE 1, 2004 BETWEEN UGI CORPORATION AND VIKING RESOURCES CORP. BOX 858 VALLEY FORGE, PA 19482 o 610-337-1000 GRAPHIC UGI CORPORATION June 8, 2004 VIA REGULAR MAIL Atlas America, Inc. Attention: Michael Brecko 311 Rouser Road P.O. Box 611 Moon Township, PA 15108 RE. GUARANTY FOR UGI ENERGY SERVICES, INC. Dear Mr. Brecko: Enclosed is the executed original Guaranty made by UGI Corporation in favor of Viking Resources, Corp., effective as of March 1, 2004. This Guaranty is intended as credit assurance for the transactions of UGI Energy Services Inc., and is given in the amount of $7,000,000. This Guaranty supercedes the prior Guaranty between the parties, which was dated effective March 1, 2004. If you have any questions concerning the foregoing, please contact me at (610) 337-1000, extension 3148. Very truly yours, graphic Frank H. Markle Counsel Attachment Cc: Andrew Koehler graphic RECEIVED JUN 10 2004 460 NORTH GULPH ROAD, KING OF PRUSSIA, PA 19406 GUARANTY This Guaranty (the "Guaranty") is made by UGI Corporation ("Guarantor"), a Pennsylvania corporation, effective as of June 1, 2004 (the "Effective Date"), in favor of Viking Resources Corp. ("Creditor"), a Pennsylvania corporation. WHEREAS, UGl Energy Services, Inc. d/b/a GASMARK ("Debtor"), a Pennsylvania corporation and Creditor are parties to various agreements for the purchase, sale and/or transportation of natural gas (whether one or more, the "Agreement"); and WHEREAS, the execution and delivery of this Guaranty is a condition to Creditor's further performance of its obligations under the terns of the Agreement and Guarantor has agreed to provide assurance for the performance of Debtor's obligations in connection with the Agreement NOW, THEREFORE, in consideration of the premises and other good and valuable consideration, the adequacy, receipt and sufficiency of which are hereby acknowledged, Guarantor hereby agrees as follows: 1. GUARANTY. Guarantor hereby unconditionally and absolutely guarantees the punctual payment when due of Debtor's payment obligations arising under the Agreement, as may be amended or modified from time to time, together with any interest thereon (collectively, the "Guaranteed Obligations"); provided, however, that the total liability of Guarantor hereunder, regardless of any amendment or modification to the Agreement, is limited to the lesser of (a) all amounts owed by Debtor to Creditor under the Agreement or Seven Million Dollars or ($7,000,000.00). Guarantor's obligations and liability under this Guaranty shall be limited to payment obligations of Debtor and Guarantor shall have no obligation to sell, deliver, supply or transport gas and/or electricity. 2. WAIVER. This is a guaranty of payment and not of collection. Guarantor hereby waives: (a) notice of acceptance of this Guaranty, of the creation or existence of any of the Guaranteed Obligations and of any action by Creditor in reliance hereon or in connection herewith; and (b) any requirement that suit be brought against, or any other action by Creditor be taken against, or any notice of default or other notice be given to, or any demand be made on, Debtor or any other person, or that any other action be taken or not taken as a condition to Guarantor's liability for the Guaranteed Obligations or as a condition to the enforcement of this Guaranty against Guarantor, except as expressly defined herein. 3. TERM: TERMINATION. This Guaranty shall continue in full force and effect for a term commencing on the Effective Date and continuing until April 30, 2006. Notwithstanding the foregoing, this Guaranty may be terminated at any time by the Guarantor by providing at least forty-five (45) days prior written notice to Creditor; provided, however, upon termination hereof, Guarantor agrees that the obligations and liabilities hereunder shall continue in full force and effect with respect to any obligations incurred prior to the termination date, plus any interest thereon, and any fees and costs of enforcement in connection herewith. This Guaranty shall continue to be effective or be restated, as the case may be, if at any time any payment of any of the Guaranteed Obligations are annulled, set aside, invalidated, declared to be fraudulent or preferential, rescinded or must otherwise be returned, refunded or repaid by Creditor upon the insolvency, bankruptcy, dissolution, liquidation or reorganization of Debtor or any other guarantor, or upon or as a result of the appointment of a receiver, intervenor or conservator of, a trustee or similar officer for, Debtor or any other guarantor or any substantial part of its property or otherwise, all as though such payment or payments had not been made. 4. DEMAND. Prior to commencing any legal proceeding to enforce this Guaranty, the Creditor shall provide the Guarantor with written demand ("Demand") setting forth Debtors obligation and providing the Guarantor or the Debtor three (3) business days in which to satisfy the obligation and thereby avoid enforcement of the Guaranty. Any Demand by Creditor hereunder shall be in writing, signed by a duly authorized officer of Creditor and delivered to the Guarantor pursuant to Section 4 hereof, and shall (a) reference this Guaranty, (b) specifically identify the Debtor, the Guaranteed Obligations to be paid and the amount of such Guaranteed Obligations and (c) set forth payment instructions. Guarantor shall pay, or cause to be paid, such Guaranteed Obligations within three (3) business days of receipt of such Demand. There are no other conditions precedent to the enforcement of this Guaranty except as set forth above. It shall not be necessary for Creditor, in order to enforce payment by Guarantor under this Guaranty, to show any proof of Debtor's default, to exhaust its remedies against Debtor, any other guarantor, or any other person liable for the payment or performance of the Guaranteed Obligations. Creditor shall not be required to mitigate damages or take any other action to reduce, collect, or enforce the Guaranteed Obligations. 5. SUBROGATION. Guarantor shall be subrogated to all rights of Creditor against Debtor in respect of any amounts paid by Guarantor pursuant to the Guaranty, provided that Guarantor waives any rights it may acquire by way of subrogation under this Guaranty, by any payment made hereunder or otherwise, until all of the Guaranteed Obligations shall have been irrevocably paid to Creditor in full. If any amount shall be paid to the Guarantor on account of such subrogation rights at any time when all the Guaranteed Obligations shall not have been paid in full, such amount shall be held 2 in trust for the benefit of Creditor and shall forthwith be paid to Creditor to be applied to the Guaranteed Obligations. 6. NOTICES. All demands, notices and other communications provided for hereunder shall. unless otherwise specifically provided herein, (a) be in writing addressed to the party receiving the notice at the address set forth below or at such other address as may be designated by written notice from effective upon delivery, when mailed by U.S. mail, registered or certified, return receipt requested, postage prepaid, or personally delivered Notices shall be sent to the following addresses: IF TO CREDITOR: Atlas America, Inc. Attention : Michael Brecko 311 Rouser Road P.O. Box 611 Moon Township, PA 15108 IF TO GUARANTOR: UGI Corporation Attention: Robert Krick, Treasurer P.O. Box 858 Valley Forge, PA 19482 7. NO WAIVER; REMEDIES. Except as to applicable statutes of limitation, no failure on the part of Creditor to exercise, and no delay in exercising, any right hereunder shall operate as a waiver thereof, nor shall any single or partial exercise of any right hereunder preclude any other or further exercise thereof or the exercise of any other right. The remedies herein provided are cumulative and not exclusive of any remedies provided by law. 8. ASSIGNMENT; SUCCESSORS AND ASSIGNS. Creditor may, upon notice to Guarantor, assign its rights hereunder without the consent of Guarantor. Guarantor may assign its rights hereunder with the prior written consent of Creditor, which consent shall not be unreasonably withheld. Subject to the foregoing, this Guaranty shall be binding upon and inure to the benefit of the parties hereto and their respective successors, permitted assigns, and legal representatives. 9. GOVERNING LAW; SUBMISSION TO JURISDICTION. THIS GUARANTY SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE COMMONWEALTH OF PENNSYLVANIA AND APPLICABLE FEDERAL LAW. 3 10. ENTIRE AGREEMENT. This Guarantee sets forth the entire understanding and agreement between the parties as to matters covered herein and expressly supersedes all prior guarantees, agreements and understandings between the parties with respect to the subject matter hereof. Any change, modification, amendment, or alteration of this Guaranty shall be in writing and no course of dealing between the parties prior or subsequent to the date of this Guaranty shall be construed to change, modify, amend, alter or waive the terms thereof IN WITNESS WHEREOF, UGI Corporation has caused this Guaranty to be duly executed and delivered by its duly authorized officer effective as of the Effective Date first written above. UGI CORPORATION By: [Signature omitted] ---------------------------- Name: Robert W.Krick -------------------------- Title: Treasurer ------------------------- 4 EX-10.9 12 ex10-9.txt EXHIBIT 10.9 Exhibit 10.9 ------------ GUARANTY AS OF DECEMBER 7, 2004 BETWEEN FIRSTENERGY CORP. AND ATLAS RESOURCES, INC. [GRAPHIC OMITTED] 76 South Main St. Akron, Ohio 44308 - ------------------------------------------------------------------------------- 1-800-533-4758 Guaranty dated as of December 7, 2004 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 Rousar Rd., Coranpolls, 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 until at least March 31, 2007, 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. /s/ Thomas C. Navin ------------------- Thomas C. Navin Treasurer 3 EX-10.10 13 ex10-10.txt EXHIBIT 10.10 Exhibit 10.10 ------------- CONFIRMATION OF GAS PURCHASE AND SALES AGREEMENT DATED NOVEMBER 17, 2004 BETWEEN ATLAS RESOURCES, INC. ET. AL. AND FIRST ENERGY SOLUTIONS CORP. FOR THE PERIOD FROM APRIL 1, 2006 THROUGH MARCH 31, 2007 PRODUCTION/CALENDAR PERIODS - ------------------------------------------------------------------------------- To: Mike Brecko From: David Frederick Co: Atlas America Co: FESC Phone: (412)262-2830x126 Phone: (330)315-7367 Fax: (412)262-3927 Fax: (330)315-7250 Date: November 17, 2004 Pages: 3 - ------------------------------------------------------------------------------- CONFIRMATION OF GAS PURCHASE AND SALES AGREEMENT Per our phone conversations this morning, this will confirm the following new price trigger pursuant to the natural gas sale and purchase agreement between Atlas Resources, Inc. et. al. as "Seller" and First Energy Solutions Corp. as "Buyer": PERIOD: April 1, 2006 through March 31, 2007 production/ calendar periods. LOCATION 1: All Seller's production delivered to National Fuel Gas Supply Corp. (NFGS) at PL00000015 and Measuring Station PSP1129541 (approximately 400,000 dth/month). PRICE 1: Priced each month at the monthly settlement value of the underlying NYMEX natural gas futures contract at expiration, plus $0.35, per Dth. (73093) LOCATION 2: Delivered to East Ohio Gas Company (EOG) at the Measuring Stations which are currently dedicated to the pools and customers of FESC (approx. 290,000 mcf/ month). PRICE 2: Priced each month at the monthly settlement value of the underlying NYMEX natural gas futures contract at expiration, plus $0.75, per Mcf. (73092) LOCATION 3: Delivered to Peoples Natural Gas Company (PNG) at the Measuring Stations which are currently dedicated to the pools and customers of FESC (approx. 16,000 mcf/ month). PRICE 3: Priced each month at the monthly settlement value of the underlying NYMEX natural gas futures contract at expiration, plus $0.68, per Mcf. (73099) (continued) - ------------------------------------------------------------------------------- The information contained in this facsimile message is privileged and confidential, and is intended only for the individual(s) or entity named above who have been specifically authorized to receive it. If the reader is not the intended recipient, you are hereby notified that any dissemination, distribution, or copying of this communication is strictly prohibited. If you have received this communication in error please notify us immediately by phone and return all pages to our corporate office at the address shown below. Thank you. - ------------------------------------------------------------------------------- November 17, 2004 PERIOD: April 1, 2006 through March 31, 2007 production/ calander periods LOCATION 4: All Seller's production delivered to Columbia Gas Transmission (TCO) at the Measuring Stations which are currently dedicated to the pools and customers of FESC (approximately 300 Dth/month) PRICE 4: Priced each month at the monthly settlement value of the underlying NYMEX natural gas futures contract at expiration, plus $0.23, per Dth. (73101) LOCATION 5: Delivered to National Fuel Gas Company (NFGD) at the Measuring Stations which are currently dedicated to the pools and customers of FESC (approx. 1500 mcf/ month). PRICE 5: Priced each month at the monthly settlement value of the underlying NYMEX natural gas futures contract at expiration, plus $0.47, per Mcf. (73096) LOCATION 6: Delivered to Tennessee Zone 4 (Tenn Z4) at the Measuring Stations which are currently dedicated to the pools and customers of FESC (approx. 180,000 Dth/ month). PRICE 6: Priced each month at the monthly settlement value of the underlying NYMEX natural gas futures contract at expiration, plus $0.26, per Dth. (73100) LOCATION 7: Delivered to Columbia Gas of Ohio (COH) at the Measuring Stations which are currently dedicated to the pools and customers of FESC (approx. 2,500 mcf/ month). PRICE 7: Priced each month at the monthly settlement value of the underlying NYMEX natural gas futures contract at expiration, plus $0.70, per Mcf (73102) (continued) - ------------------------------------------------------------------------------- The information contained in this facsimile message is privileged and confidential, and is intended only for the individual(s) or entity named above who have been specifically authorized to receive it. If the reader is not the intended recipient, you are hereby notified that any dissemination, distribution, or copying of this communication is strictly prohibited. If you have received this communication in error please notify us immediately by phone and return all pages to our corporate office at the address shown below. Thank you. - ------------------------------------------------------------------------------- Page 2 November 17, 2004 PERIOD: April 1, 2006 through March 31, 2007 production/calander periods ADDITIONAL FLOORS AND TRIGGERS Buyer is prepared to negotiate price floors and/or triggered fixed prices with Seller for any portion of the volume contracted above. Seller is responsible to deliver a minimum monthly volume at each location identified above equal to the total volume involved at each location in all price-triggered and/or floor-priced portions of this agreement (currently zero). Seller agrees to keep Buyer economically whole in the event that Seller's inability to deliver the minimum monthly volume adversely impacts Buyer's purchased gas cost. Buyer is to buy all production at the above meters. NFGS and TENN Z4 production will be held to a 20% tolerance of the nominated volume. APPROVED: /s/ David A. Frederick /s/ Jeffrey C. Simmons Exec VP ---------------------- ------------------------------ David A. Frederick Jeffrey C. Simmons FirstEnergy Solutions Corp. Atlas America - ------------------------------------------------------------------------------- The information contained in this facsimile message is privileged and confidential, and is intended only for the individual(s) or entity named above who have been specifically authorized to receive it. If the reader is not the intended recipient, you are hereby notified that any dissemination, distribution, or copying of this communication is strictly prohibited. If you have received this communication in error please notify us immediately by phone and return all pages to our corporate office at the address shown below. Thank you. - ------------------------------------------------------------------------------- Page 3 EX-10.11 14 ex10-11.txt EXHIBIT 10.11 Exhibit 10.11 TRANSACTION CONFIRMATION DATED DECEMBER 14, 2004 BETWEEN ATLAS AMERICA, INC. AND UGI ENERGY SERVICES, INC. D/B/A/ GASMARK Revised EXHIBIT A TRANSACTION CONFIRMATION FOR IMMEDIATE DELIVERY Atlas America, Inc. Date: December 14, 2004 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: Atlas America, Inc. UGI Energy Services, 311 Rouser Corp. Inc. d/b/a GASMARK Moon Two, PA 15108 1100 Berkshire Attn: Michael Brecko Blvd., Suite 305 Phone: 412-262-2830x126 Wyomissing, PA 19610 Fax: 412-262-3927 Attn: Robert Meder Base Contract No. Phone: 610-373-7989 Transporter: Fax: 610-374-4288 Transporter Contract Number: Base Contract No. Transporter: Transporter Contract Number: Contract Price $________ /MMBtu or NYMEX LDS plus $.75 payable on Adjusted Mcfs. Delivery Period: Begin: June 1, 2005 End: March 31, 2007 Performance Obligation and Contract Quantity: (Select One) Firm (Fixed Quantity): Firm (Variable Quantity) Interruptible: ________ MMBtus/day 2,500 MMBtus/day Up to ________ MMBtus/day |_| EFP subject to Section 4.2 at election of |_| Buyer or |_| Seller Delivery Point(s): Various meters located on Dominion East Ohio's pipeline system (If a pooling point is used, list a specific geographic and pipeline location): Special Conditions: Additional walls may be added upon mutual consent of the parties. All gas produced under this agreement shall be produced from wells located within the state of Ohio. Atlas America shall have trigger rights to lock in prices. Adjusted Mcfs are the actual Mcfs at the meter converted to MMBtu's using a conversion factor of 1.109 to get total MMBtu's. The total MMBtu's are converted to Adjusted Mcfs by dividing the MMBtu's by a factor of 1.036. These conversion factors are set by Dominion East Ohio and are subject to change by Dominion East Ohio. Atlas America has chosen to lock in prices on the volumes produced each month as per the attached "Confirmation of Price Locks". All volumes sold in excess of the locked in volumes shall continue to be priced as per the pricing clause above. Seller: Atlas America, Inc. Buyer: UGI Energy Services, Inc., d/b/a GASMARK By:____________________________________ By:____________________________________ Title:_________________________________ Title: Vice President, Gas Supply & Risk Management Date:__________________________________ Date:__________________________________ - ------------------------------------------------------------------------------- Copyright (C) 2002 North American Energy Standards Board, Inc. NAESB Standard 6.3.1 All Rights Reserved Page 1 of 10 April 19, 2002 Revised EXHIBIT A TRANSACTION CONFIRMATION FOR IMMEDIATE DELIVERY Atlas America, Inc. Date: December 14, 2004 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: Atlas America, Inc. UGI Energy Services, 311 Rouser Corp. Inc. d/b/a GASMARK Moon Two, PA 15108 1100 Berkshire Blvd., Suite 305 Attn: Michael Brecko Wyomissing, PA 19610 Phone: 412-262-2830x126 Attn: Robert Meder Fax: 412-262-3927 Phone: 610-373-7999 Base Contract No. Fax: 610-374-4288 Transporter: Base Contract No. Transporter Contract Number: Transporter: Transporter Contract Number: Contract Price $________ /MMBtu or NYMEX LDS plus $.385 per Dth Delivery Period: Begin: April 1, 2006 End: March 31, 2007 Performance Obligation and Contract Quantity: (Select One) Firm (Fixed Quantity): Firm (Variable Quantity) Interruptible: ________ MMBtus/day 20,000 MMBtus/day Up to ________ MMBtus/day |_| EFP subject to Section 4.2 at election of |_| Buyer or |_| Seller Delivery Point(s): Texas Eastern Meter Number 73133, Station Name of Prah and the Joseph Meter in Market area M2 (If a pooling point is used, list a specific geographic and pipeline location): 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. Atlas America shall have trigger rights to lock in prices. Atlas America has chosen to lock in prices on the volumes produced each month as per the attached "Confirmation of Price Locks". All volumes sold in excess of any locked in volumes shall continue to be priced as per the pricing clause above. Seller: Atlas America, Inc. Buyer: UGI Energy Services, Inc.,d/b/a GASMARK By:____________________________________ By:____________________________________ Title:_________________________________ Title: Vice President, Gas Supply & Risk Management Date:__________________________________ Date:__________________________________ - ------------------------------------------------------------------------------- Copyright (C) 2002 North American Energy Standards Board, Inc. NAESB Standard 6.3.1 All Rights Reserved Page 1 of 10 April 19, 2002 EX-10.12 15 ex10-12.txt EXHIBIT 10.12 EXHIBIT 10.12 ------------- GUARANTY DATED JANUARY 1, 2005 BETWEEN UGI CORPORATION AND VIKING RESOURCES CORP. GUARANTY This Guaranty (the "Guaranty") is made by UGI Corporation ("Guarantor"), a Pennsylvania corporation, effective as of January 1, 2005 (the "Effective Date"), in favour of Viking Resources Corp. ("Creditor"), a Pennsylvania corporation. WHEREAS, UGI Energy Services, Inc. d/b/a GASMARK ("Debtor"), a Pennsylvania corporation and Creditor are parties to various agreements for the purchase, sale and/or transportation of natural gas (whether one or more, the "Agreement"); and WHEREAS, the execution and delivery of this Guaranty is a condition to Creditor's further performance of its obligations under the terms of the Agreement and Guarantor has agreed to provide assurance for the performance of Debtor's obligations in connection with the Agreement. NOW, THEREFORE, in consideration of the premises and other good and valuable consideration, the adequacy, receipt and sufficiency of which are hereby acknowledged, Guarantor hereby agrees as follows: 1. GUARANTY. Guarantor hereby unconditionally and absolutely guarantees the punctual payment when due of Debtor's payment obligations arising under the Agreement, as may be amended or modified from time to time, together with any interest thereon (collectively, the "Guaranteed Obligations"); provided, however, that the total liability of Guarantor hereunder, regardless of any amendment or modification to the Agreement, is limited to the lesser of (a) all amounts owed by Debtor to Creditor under the Agreement or Seven Million Dollars or ($7,000,000.00). Guarantor's obligations and liability under this Guaranty shall be limited to payment obligations of Debtor and Guarantor shall have no obligation to sell, deliver, supply or transport gas and/or electricity. 2. WAIVER. This is a guaranty of payment and not of collection. Guarantor hereby waives: (a) notice of acceptance of this Guaranty, of the creation or existence of any of the Guaranteed Obligations and of any action by Creditor in reliance hereon or in connection herewith; and (b) any requirement that suit be brought against, or any other action by Creditor be taken against, or any notice default or other notice be given to, or any demand be made on, Debtor or any other person, or that any other action be taken or not taken as a condition to Guarantor's liability for the Guaranteed Obligations or as a condition to the enforcement of this Guaranty against Guarantor, except as expressly defined herein. 3. TERM: TERMINATION. This Guaranty shall continue in full force and effect for a term commencing on the Effective Date and continuing until March 31, 2007. Notwithstanding the foregoing, this Guaranty may be terminated at any time by the Guarantor by providing at least forty-five (45) days prior written notice to Creditor; provided, however, upon termination hereof, Guarantor agrees that the obligations and liabilities hereunder shall continue in full force and effect with respect to any obligations incurred prior to the termination date, plus any interest thereon, and any fees and costs of enforcement in connection herewith. This Guaranty shall continue to be effective or be reinstated, as the case may be, if at any time any payment of any of the Guaranteed Obligations are annulled, set aside, invalidated, declared to be fraudulent or preferential, rescinded or must otherwise be returned, refunded or repaid by Creditor upon the insolvency, bankruptcy, dissolution, liquidation or reorganization of Debtor or any other guarantor, or upon or as a result of the appointment of a receiver, intervenor or conservator of, or trustee or similar officer for, Debtor or any other guarantor or Any substantial part of its property or otherwise, all as though such payment or payments had not been made. 4. DEMAND. Prior to commencing any legal proceeding to enforce this Guaranty, the Creditor shall provide the Guarantor with written demand ("Demand") setting forth Debtors obligation and providing the Guarantor or the Debtor three (3) business days in which to satisfy the obligation and thereby avoid enforcement of the Guaranty. Any Demand by Creditor hereunder shall be in writing, signed by a duly authorized officer of Creditor and delivered to the Guarantor pursuant to Section 4 hereof, and shall (a) reference this Guaranty, (b) specifically identify the Debtor, the Guaranteed Obligations to be paid and the amount of such Guaranteed Obligations and (c) set forth payment instructions. Guarantor shall pay, or cause to be paid, such Guaranteed Obligations within three (3) business days of receipt of such Demand. These are no conditions precedent to the enforcement of this Guaranty, except as set forth above. It shall not be necessary for Creditor, in order to enforce payment by Guarantor under this Guaranty, to show any proof of Debtor's default, to exhaust its remedies against Debtor, any other guarantor, or any other person liable for the payment or performance of the Guaranteed Obligations. Creditor shall not be required to mitigate damages to take any other action to reduce, collect, or enforce the Guaranteed Obligations. 5. SUBROGATION. Guarantor shall be subrogated to all rights of Creditor against Debtor in respect of any amounts paid by Guarantor pursuant to the Guaranty, provided that Guarantor waives any rights it may acquire by way of subrogation under this Guaranty, by any payment made hereunder or otherwise, until all of the Guaranteed Obligations shall have been irrevocably paid to Creditor in full. If any amount shall be paid to the Guarantor on account of such subrogation rights at any time when all the Guaranteed Obligations shall not have been paid in full, such amount shall be held 2 in trust for the benefit of Creditor and shall forthwith be paid to Creditor to be applied to the Guaranteed Obligations. 6. NOTICES. All demands, notices and other communications provided for hereunder shall, unless otherwise specifically provided herein, (a) be in writing addressed to the party receiving the notice at the address set forth below or at such other address as may be designated by written notice, from time to time, to the other party, and (b) be effective upon delivery, when mailed by U.S. mail, registered or certified, return receipt requested, postage prepaid, or personally delivered. Notice shall be sent to the following addresses: IF TO CREDITOR: Atlas America, Inc. Attention: Michael Brecko 311 Rouser Road P.O. Box 611 Moon Township, PA 15108 IF TO GUARANTOR: UGI Corporation Attention: Robert Krick, Treasurer P.O. Box 858 Valley Forge, PA 19482 7. NO WAIVER: REMEDIES. Except as to applicable statutes to limitation, no failure on the part of Creditor to exercise, and no delay in exercising, any right hereunder shall operate as a waiver thereof, nor shall any single or partial exercise of any right hereunder preclude any other or further exercise thereof or the exercise of any other right. The remedies herein provided are cumulative and not exclusive of any remedies provided by law. 8. ASSIGNMENT: SUCCESSORS AND ASSIGNS. Creditor may, upon notice to Guarantor, assign its rights hereunder without the consent of Guarantor. Guarantor may assign its rights hereunder with the prior written consent of Creditor, which consent shall not be unreasonably withheld. Subject to the foregoing, this Guaranty shall be binding upon and inure to the benefit of the parties hereto and their respective successors, permitted assigns, and legal representatives. 9. GOVERNING LAW: SUBMISSION TO JURISDICTION. THIS GUARANTY SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE COMMONWEALTH OF PENNSYLVANIA AND APPLICABLE FEDERAL LAW. 3 10. ENTIRE AGREEMENT. This Guarantee sets forth the entire understanding and agreement between the parties as to matters covered herein and expressly supersedes all prior guarantees, agreements and understandings between the parties with respect to the subject matter hereof. Any change, modification, amendment, or alteration of this Guaranty shall be in writing and no course of dealing between the Parties prior or subsequent to the date of this Guaranty shall be construed to change, modify, amend, alter or waive the terms hereof. IN WITNESS WHEREOF, UGI Corporation has caused this Guaranty to be duly executed and delivered by its duly authorized officer effective as of the Effective Date first written above. UGI CORPORATION By: /s/ Robert W. Krick --------------------------- Name: Robert W. Krick Title: Treasurer 4 EX-10.13 16 ex10-13.txt EXHIBIT 10.13 EXHIBIT 10.13 ------------- DRILLING AND OPERATING AGREEMENT DATED SEPTEMBER 15, 2004 BY AND BETWEEN ATLAS AMERICA, INC. AND KNOX ENERGY, LLC
TABLE OF CONTENTS ----------------- PAGE ---- 1. Definitions..............................................................................................1 2. Minimum Well Drilling Schedule; Initial and Subsequent Drilling; Election to Participate; Gathering......3 3. Title; Lease Status; Assignment by Non-Operator; AMI Election............................................8 4. Drilling and Certain Related Procedures; Abandonment....................................................11 5. Other Operating Responsibilities of the Operator........................................................13 6. Marketing of Natural Gas and Oil........................................................................14 7. Superintendence and Maintenance of the Wells; Operator's Fee and Other Charges..........................16 8. Costs and Expenses; Plugging Reserve Account............................................................17 9. Additional Operations...................................................................................19 10. Non-Operator's Access; Audit............................................................................20 11. Term and Termination....................................................................................20 12. Contract Not Assignable.................................................................................22 13. Relationship; Internal Revenue Code Election............................................................22 14. Force Majeure...........................................................................................22 15. Notices.................................................................................................23 16. Governing Law...........................................................................................24 17. Successors in Interest..................................................................................24 18. Integration; Amendment; Interpretation..................................................................24 19. Severability............................................................................................24 20. Waivers.................................................................................................24 21. Further Assurances......................................................................................25 22. Attorneys' Fees.........................................................................................25 23. Public Statements.......................................................................................25 24. Counterpart; Fax........................................................................................25
- i - DEFINITIONS TERM DEFINED AT: - ---- ---------- Additional Potential Lease(s) ss. 3.4 AFE ss. 2.5 Affiliate ss. 4.3 Agreement Page 1 AMI Second Whereas clause, page 1 Assignment ss. 1.1(a) Casing Point ss. 1.1(b) Completion ss. 1.1(c) COPAS ss. 7.3 Drilling Acreage ss. 1.1(d) Drilling Costs ss. 2.5 Dry Hole ss. 1.1(e) force majuere ss. 14.1 Gas Purchaser ss. 1.1(f) Initial Period ss. 2.8 Leases/Lease Second Whereas clause, page 1 Net Revenue ss. 1.1(h) Net Well ss. 2.8 Non-Operator Page 1 Operating Expenses ss. 1.1(i) Operating Reserve Account ss. 8.1 Operator Page 1 Operator's Fee ss. 7.3 Option Period ss. 2.8 Plugging Funds ss. 8.4 Plugging Reserve Account ss. 8.4 Proportionate Share ss. 1.1(j) Well Acreage ss. 1.1(l) Wells/Well ss. 1.1(k) - ii -
LIST OF EXHIBITS ---------------- PRINCIPAL REFERENCE: ------------------- Exhibit A - AMI Map Second Whereas clause, page 1 Exhibit B - Leases and Additional Potential Leases, Minimum Wells and Excluded Acreage First Whereas clause, page 1 Exhibit C - AFE's ss. 2.3 Exhibit D - Assignment ss. 1.1(a) Exhibit E - Gas Balancing Agreement ss. 6.4
- iii - DRILLING AND OPERATING AGREEMENT -------------------------------- This Drilling and Operating Agreement (this "Agreement") is made and entered into, effective as of the 15th day of September, 2004, by and between ATLAS AMERICA, INC., a Pennsylvania corporation (and not any other entity having the name Atlas America, Inc. or any derivative thereof), whose address is 311 Rouser Road, Moon Township, Coraopolis, PA 15108 (hereinafter referred to as "Operator") and KNOX ENERGY, LLC, a Tennessee limited liability company, whose address is 132 Mitchell Road, Oak Ridge, TN 37830 (hereinafter referred to as "Non-Operator"). WHEREAS, by the agreements described in Exhibit B which is attached hereto and made a part hereof, Non-Operator is vested with the right to drill one or more wells for the purpose of exploring for and producing natural gas and/or oil from the tracts or parcels covered thereby situate in Anderson, Campbell, Morgan, Roane and Scott Counties, Tennessee; and WHEREAS, Operator and Non-Operator desire to drill wells on the property covered by the agreements described in Exhibit B (as well as any other agreements granting Non-Operator, either of the members of Non-Operator and/or any affiliate of any of them the right to drill one or more wells on the property within the area of mutual interest (the "AMI") outlined on the map attached hereto as Exhibit A and made a part hereof) for the production of natural gas and/or oil therefrom, and the processing, transportation and marketing of such natural gas and/or oil, on the terms and conditions hereinafter set forth; the agreements described in Exhibit B, as well as any other agreements described in this WHEREAS clause which are deemed Leases as set forth in Section 3.4 hereof, are referred to herein collectively as the "Leases" and individually as a "Lease". NOW, THEREFORE, WITNESSETH, that for and in consideration of the foregoing premises, and the mutual covenants herein contained, the parties hereto mutually covenant and agree as follows: 1. Definitions ----------- 1.1 The following terms used in this Agreement shall have the meanings set forth below: (a) The term "Assignment" shall mean, with respect to Wells (as defined below), the separate agreement in the form attached hereto and made a part hereof as Exhibit D, whereby Non-Operator will grant, assign and convey, as set forth herein, unto the Operator and/or its successor and assigns, their Proportionate Share (as defined below) of the right, title and interest of Non-Operator in and to a part or portion of the property described in and covered by the Leases. (b) The term "Casing Point" means the time when a Well has been drilled to the depth or the formation or formations hereinafter designated and such tests have been conducted so that a determination can be made as to whether the Well can be further developed to completion. (c) The term "Completion" means in the case of a natural gas Well or an oil Well the time when all Well equipment has been installed and the Well is capable of producing natural gas and/or oil without regard to whether all facilities necessary to permit the delivery of natural gas or oil production from the Well to a purchaser have been installed. (d) The term "Drilling Acreage" shall mean those tracts or parcels of land, or the parts or portions thereof other than the 1.628 acre, more or less, parcel referred to in Section 2.8 hereof, covered by the Leases. (e) The term "Dry Hole" means a Well that has been drilled to the Casing Point but which is not completed pursuant to the provisions of this Agreement. (f) The term "Gas Purchaser" shall mean that party, whether one or more, designated by the Operator and/or the Non-Operator to purchase gas produced from one or more Wells. (g) The term "Net Revenue" shall mean the gross receipts of the Wells less all royalties, overriding royalties, the Operator's Fee (as defined in Section 7.3 hereof) and Operating Expenses (as defined below) and any other item of expense not expressly chargeable to the Operator. (h) The term "Operating Expenses" shall mean the customary expense of operation and maintenance of a Well, if it is producing, the production and marketing of natural gas and/or oil therefrom, and of plugging and abandoning a Well, if unproductive. Such term includes business and occupation, gross receipts, ad valorem and severance taxes and all other taxes payable with respect to the production from the Wells, and all legal fees, all transportation charges (including compression charges), all materials utilized in production, such as, but not limited to, alcohol, soap, solvents, cleaners, electric drops, electricity and other similar items and any other item commonly or ordinarily used in connection with producing a natural gas and/or oil well or designated as an Operating Expense in this Agreement, but shall not include any cost or expense incurred by the Operator in discharging its obligation to superintend and maintain a Well, if producing (for which the Operator is to receive monthly payments as set forth in Section 7.3 hereof) or any other such costs and expenses which the Operator is required by the terms of this Agreement to bear itself. Such term shall also include any amounts payable as damages subsequent to reclamation of all well roads and drill sites in accordance with applicable law to any owner of the surface estate where a Well is drilled or any right of way or easement appurtenant thereto and costs of defending or arbitrating any action or claims asserted with respect thereto. (i) The term "Proportionate Share" shall mean the percentage share of Operator or its successors or assigns and of Non-Operator in the drilling and completion costs, Operating Expenses, Operator's Fee, working interest, production revenues and ownership of each Well to be drilled pursuant to this Agreement. (j) The term "Well" shall mean a well, and the term "Wells" shall mean all wells, drilled in accordance with the terms of this Agreement. (k) The term "Well Acreage" shall mean that part or portion of the Drilling Acreage covered by one or more Leases included in a square area of forty (40) acres having as its center the borehole of a Well to the extent such part or portion shall fall within the boundaries of such square area, provided, however, that if a Lease, or any governmental or other regulatory - 2 - authority or agency, provides or requires for a larger area or a different configuration, the Well Acreage shall mean such larger area and/or different configuration. 2. Minimum Well Drilling Schedule; Initial and Subsequent Drilling; Election to Participate; Gathering ---------------------------------------------------------------- 2.1 The Leases identified in Exhibit B provide that a minimum number of wells are to be drilled before certain dates as set forth on Exhibit B as a condition to the drilling of additional wells on the property subject to such Leases. 2.2 It is understood and agreed by the parties that Operator is presently unable to perform the duties and obligations of Operator hereunder with respect to (i) permitting and titling of Wells, (ii) drilling and completing Wells, (iii) accounting for the costs of drilling and completing Wells, (iv) tending Wells, (v) marketing production from the Wells or (vi) accounting for, and distributing, Net Revenues and royalties and overriding royalties relating to production from the Wells. The parties agree that Non-Operator will initially perform such duties and obligations and shall be entitled to receive payment from Operator of Operator's Proportionate Share of the Drilling Costs, Operating Expenses and Operator's Fee relating thereto. The parties will fully cooperate with each other and use all reasonable efforts to have Operator perform such duties and obligations relating to each of the foregoing numbered activities as soon as reasonably practicable (giving due consideration to effecting a smooth transition as to each of the foregoing numbered activities when Operator has adequate personnel in place to perform such duties and obligations with respect to such activities), provided, however, that Operator shall perform all such duties and obligations no later than when fifty (50) Wells have been drilled hereunder. For example and without limiting the foregoing, until such time as Operator obtains any and all required governmental and other approvals and permissions to drill, complete and operate Wells on the property subject to a Lease identified in Exhibit B and has adequate personnel in place to conduct such activities, Non-Operator shall perform such activities, and shall have all of the rights, of Operator hereunder with respect to such activities. Operator shall promptly and diligently pursue all reasonable actions to obtain such approvals and permissions and have such adequate personnel in place. Upon obtaining such approvals and permissions and having such personnel in place, Operator shall thereafter perform all such activities, and shall have all of the rights, of Operator hereunder with respect to such activities and Non-Operator shall promptly transfer to Operator all permits and other authorizations to drill, complete and operate Wells on the property subject to the Leases identified in Exhibit B. 2.3 Non-Operator has obtained all governmental and other approvals and permits to drill, complete and operate wells on the property subject to the Leases identified in Exhibit B as set forth on Exhibit B under the heading Presently Permitted Minimum Wells. Until Operator obtains any and all required governmental and other approvals and permissions to drill, complete and operate Wells on the property subject to a Lease identified in Exhibit B, Non-Operator shall promptly and diligently pursue all reasonable action to obtain such approvals and permissions to drill, complete and operate, and shall drill, the minimum number of Wells set forth on Exhibit B with respect to such Lease. After obtaining any and all required approvals and permissions to drill, complete and operate Wells on the property subject to a Lease identified in Exhibit B, Operator shall promptly and diligently drill the minimum number of wells set forth on Exhibit B with respect to such Lease (less the number previously drilled) during the periods Operator has the right to drill wells under this Agreement. - 3 - With respect to each of the first ten (10) Wells identified in Exhibit B under the heading Presently Permitted Minimum Wells, Operator shall pay to Non-Operator, upon execution of this Agreement, Operator's Proportionate Share of the Drilling Costs (as defined in Section 2.5 hereof) as estimated in the AFE (as defined in Section 2.5 hereof) for such Well attached hereto as Exhibit C and made a part hereof, and after Non-Operator determines the final third-party costs of drilling and completing such Well, Operator shall pay to Non-Operator, as set forth in Section 2.5 hereof, Operator's Proportionate Share of such final costs in excess of the amounts set forth in the AFE for such Well, subject to the refund or credit set forth in such Section. With respect to any other Well which is drilled and completed by Non-Operator, not later than five (5) days prior to such drilling, Operator shall pay to Non-Operator the Operator's Proportionate Share of the Drilling Costs as estimated in the AFE for such Well, and after Non-Operator determines the final third-party costs of drilling and completing such Well, Operator shall pay to Non-Operator, as set forth in Section 2.5 hereof, Operator's Proportionate Share of such final costs in excess of the amounts set forth in the AFE for such Well, subject to the refund or credit set forth in such Section. Operator and Non-Operator agree that no other well will be drilled on the property subject to the Leases closer than one thousand three hundred twenty (1,320) feet to any Well drilled pursuant hereto unless Operator and Non-Operator otherwise agree in writing; provided, however, that after the expiration of the Initial Period or, if applicable, the Option Period, or the termination of this Agreement if such termination occurs prior to the expiration of the Initial Period or the Option Period, Non-Operator shall have the right to drill wells on the property subject to the Leases which are closer than one thousand three hundred twenty (1,320) feet to any Well drilled pursuant hereto so long as no such well produces natural gas or oil from any formation (other than methane gas from coal beds or coal mines) from the surface to one hundred (100) feet below the deepest formation from which natural gas and/or oil is produced from any such Well and so long as the drilling, completion and operation (including the production, compression and transportation of natural gas and/or oil) of all such wells do not unduly interfere with the operation (including the production, compression and transportation of natural gas and/or oil) of any Well and provided, further, that if a Well is plugged and abandoned, the limitations as to formations and interference in the foregoing proviso as to such Well shall not apply. If Non-Operator drills a well which is closer than one thousand three hundred twenty (1,320) feet to any Well which has not been plugged and abandoned, it shall promptly furnish to Operator copies of all drilling reports, logs, completion reports and other data reasonably requested by Operator for the purpose of verifying that such well is not producing, and will not produce, any natural gas or oil from any formation (other than methane gas from coal beds or coal mines) from the surface to one hundred (100) feet below the deepest formation from which natural gas and/or oil is produced from such Well. The agreements set forth above in this paragraph shall be covenants running with the land and shall be set forth by reference to this Agreement in the Assignment in the form attached hereto as Exhibit D and made a part hereof. 2.4 Non-Operator shall have the right to participate, on a well-by-well basis, for up to fifty percent (50%) of the working interests in each Well drilled hereunder. Except as set forth in Exhibit B under the heading Wells To Be Drilled On Or Before March 31, 2005, Operator shall propose the number and location of the Wells to be drilled pursuant hereto and shall give written notice thereof to Non-Operator. Non-Operator may elect to participate by giving written notice to Operator of such election within thirty (30) days after receipt of Operator's proposal. Failure of Non-Operator to give notice to - 4 - Operator of its election to participate within the period set forth above shall be deemed, and shall constitute, an election by Non-Operator not to participate. Non-Operator has elected not to participate in the first ten (10) proposed Wells identified in Exhibit B under the heading Presently Permitted Minimum Wells for any working interest and Operator shall own one hundred percent (100%) of the working interests in such Wells. 2.5 Operator and Non-Operator shall each pay its Proportionate Share of the actual third-party costs of drilling and completing each Well plus an amount to cover general and administrative, and technical supervision, expenses allocated to the drilling and completion of each Well (the "Drilling Costs"). For each Well for which the drilling is commenced prior to March 31, 2005, the amount allocated for general and administrative, and technical supervision, expenses for the drilling and completion of each such Well shall be Fourteen Thousand Dollars ($14,000). Thereafter, for each annual period beginning April 1 and ending March 31 of the following year, Operator shall determine the amount to be allocated for general and administrative, and technical supervision, expenses allocated to the drilling and completion of a Well for which the drilling is commenced during such period, such amount to be equal to the amount Operator allocates to Wells drilled for any limited partnership or other entity from which Operator receives funds to drill such Wells. Operator shall give Non-Operator thirty (30) days' prior written notice of the anticipated drilling date for a Well in which Non-Operator has elected to participate. No later than five (5) days prior to the drilling by Operator of a Well in which Non-Operator has elected to participate, Non-Operator shall pay to Operator its Proportionate Share of the Drilling Costs of the Well as estimated in an Authority for Expenditure ("AFE") to be furnished to Non-Operator by Operator along with the written notice to be provided by Operator to Non-Operator pursuant to Section 2.4 hereof. Within thirty (30) days after Operator determines the final third-party costs of drilling and completing a Well, Operator shall either (i) invoice Non-Operator for its Proportionate Share of the final costs in excess of the amount prepaid by Non-Operator and Non-Operator shall pay such invoice within thirty (30) days after receipt or (ii) at the election of Non-Operator, Operator shall refund to Non-Operator, or credit against Non-Operator's Proportionate Share of the Drilling Costs for one or more other Wells in which it has elected to participate, the amount prepaid by Non-Operator in excess of the final Drilling Costs for the Well. It is expressly understood and agreed that if the final Drilling Costs for a Well exceed one hundred ten percent (110%) of the Drilling Costs as estimated in the AFE for the Well, Non-Operator shall have no obligation to pay more than its Proportionate Share (based upon its election to participate in the Well pursuant to Section 2.4 hereof) of such excess, provided, however, that if Non-Operator does not pay such Proportionate Share of the excess, its Proportionate Share of the Well shall be reduced to a share equal to the share of the final Drilling Costs of the Well paid by it. 2.6 If Non-Operator elects to participate in a Well for a fifty-percent (50%) working interest, the Well will be burdened with an overriding royalty payable to Non-Operator equal to 1/64th (1.5625%); if Non-Operator does not elect to participate in a Well for any working interest, the Well will be burdened with an overriding royalty payable to Non-Operator equal to 1/32nd (3.125%). To the extent that Non-Operator participates in a Well for less than a fifty-percent (50%) working interest, the overriding royalty to Non-Operator shall be determined by subtracting from an overriding royalty of 1/32nd (3.125%) an amount determined by multiplying 1/64th (1. 5625%) by a fraction, the numerator of which is the Non-Operator's working interest and the denominator of which is fifty percent (50%). For example, if Non-Operator elects - 5 - to participate for a thirty-percent (30%) working interest in a Well, the overriding royalty to Non-Operator shall be: 3.125% less (1.5625% x (30% / 50%)) = 3.125% less .9375% = 2.1875% 2.7 With respect to each of the first ten (10) Wells identified in Exhibit B under the heading Presently Permitted Minimum Wells, Operator shall pay to Non-Operator, upon execution of this Agreement, Operator's Proportionate Share of a site fee of Four Thousand Dollars ($4,000) and a completion fee of Two Thousand Dollars ($2,000) for each such Well. With respect to each other Well drilled and completed during the Initial Period (as defined in Section 2.8 hereof), Operator shall pay to Non-Operator, not later than five (5) days prior to drilling such Well, Operator's Proportionate Share of a site fee of Four Thousand Dollars ($4,000) and Operator shall pay to Non-Operator, not later than thirty (30) days after completion of such Well, Operator's Proportionate Share of a completion fee of Two Thousand Dollars ($2,000). During the Option Period (as defined in Section 2.8 hereof), if applicable, the site fee shall be Five Thousand Dollars ($5,000) and the completion fee shall be Two Thousand Five Hundred Dollars ($2,500). 2.8 During the period ending June 30, 2007 (the "Initial Period"), Operator shall have the exclusive right to propose and drill three hundred (300) Net Wells (as defined in this Section 2.8) under this Agreement inclusive of Wells identified in Exhibit B under the heading Presently Permitted Minimum Wells and other Wells drilled by Non-Operator under Section 2.3 hereof. If agreed to by Non-Operator in writing no later than December 31, 2006, Operator shall have the exclusive right to propose and drill two hundred (200) additional Net Wells under this Agreement during the period commencing July 1, 2007 and ending June 30, 2009 (the "Option Period"). For purposes of this Agreement, a Net Well shall mean one or more Wells in which Operator's (and its successors' and assigns') total initial participation equals one hundred percent (100%) of the working interests; for example, if Operator has a working interest of one hundred percent (100%) in each of four (4) Wells, seventy-five percent (75%) in each of four (4) Wells and fifty percent (50%) in each of four (4) Wells, the number of Net Wells shall be four (4), three (3) and two (2), respectively, or a total of nine (9) Net Wells. Subject to the performance by Non-Operator of its obligations, and the accuracy of its representations and warranties, herein contained (including but not limited to those set forth in Section 2.3 hereof, this Section 2.8 and Section 3.2 hereof) and subject to the provisions of Section 14 hereof, Operator shall drill the minimum number of Wells set forth in the Leases to keep each such Lease in full force and effect during the Initial Period and, if applicable, during the Option Period and, except with respect to the minimum number of Wells to be drilled prior to March 31, 2005 and one (1) Well to be drilled under the Brimstone Lease on or before June 1, 2005 as set forth in Exhibit B, Operator shall commence the drilling of such minimum number of Wells no later than ninety (90) days prior to the dates set forth in each of the Leases to keep each of the Leases in full force and effect during the Initial Period and, if applicable, during the Option Period. Notwithstanding the provisions of the foregoing sentence, (i) if Non-Operator substitutes a new Operator under Section 11.2 hereof, Operator shall have no obligation, nor right, to drill any additional Wells and (ii) if the expiration of the Initial Period or, if applicable, the Option Period, occurs during a period when a Lease provides a minimum number of Wells is to be drilled to keep such Lease in full force and effect, the obligation of Operator to drill the minimum number of Wells to keep such Lease in full force and effect shall be prorated based upon the time of such period prior to, and after, the expiration of the Initial Period and, if applicable, the Option Period; for example, if the period in the - 6 - Lease during which a minimum number of Wells to be drilled is from January 1 of a year to December 31 of such year and the minimum number of Wells to be drilled in such period is ten (10), then in the calendar year 2007, Operator shall have an obligation to drill only five (5) Wells if the Option Period is not applicable. Failure of the Operator to drill the minimum number of Wells as set forth above in the preceding paragraph shall result in the immediate termination of Operator's right to thereafter drill any Well and, except as set forth below, Operator's right or obligation to participate in any Well thereafter drilled, provided, however, that if after such termination, Non-Operator drills, or causes to be drilled, any Wells during the Initial Period or if applicable, the Option Period, to satisfy the minimum number of Wells as set forth in the preceding paragraph to be drilled in such period, Operator shall participate in each such Well drilled no deeper than one hundred (100) feet below the Chattanooga Shale formation (or such deeper formation to which such Well is required to be drilled by a Lease) for such working interests, if any, as Non-Operator shall notify Operator in writing prior to the drilling of such Well and Operator shall be responsible for, and shall pay, its Proportionate Share of the Drilling Costs, Operating Expenses and Operator's Fee for such Well; the termination of the rights of Operator set forth above and the right of Non-Operator to require Operator to participate in the minimum number of Wells drilled no deeper than one hundred (100) feet below the Chattanooga Shale formation (or such deeper formation to which such Well is required to be drilled by a Lease) shall be the sole and exclusive remedy of Non-Operator with respect to Operator's failure to drill the minimum number of Wells as set forth above in the preceding paragraph. Non-Operator represents and warrants, to the best of its knowledge, to and for the benefit of Operator and its successors and assigns that no person, corporation or other entity, other than Non-Operator, has the right to explore for or produce natural gas or oil (including the right to drill, complete and operate Wells for the production, compression, transportation, marketing and sale of natural gas and oil produced therefrom) from the property subject to the Leases identified in Exhibit B other than the 1.628 acre, more or less, portion of the tract covered by the Coal Creek Lease described in Exhibit B under the heading Excluded Acreage. Non-Operator agrees that during the Initial Period, and if applicable, during the Option Period, Non-Operator shall not grant, assign or otherwise transfer to any person, corporation or other entity, except to Operator as set forth herein, the right to explore for and produce natural gas or oil from the property subject to the Leases not including methane gas from coal beds and coal mines. Notwithstanding anything to the contrary contained in this Agreement, upon the expiration of the Initial Period and, if applicable, the Option Period, Operator shall have no obligation or right to drill any well, and shall have no right to participate in any well drilled thereafter, on the property subject to any Lease. 2.9 Notwithstanding anything to the contrary contained in this Agreement, without the written consent of Non-Operator, no Well drilled under this Agreement shall be drilled or completed to produce any methane gas from coal beds or coal mines, and after the initial drilling and completion of a Well, such Well shall not be deepened without the consent of both Operator and Non-Operator. It is expressly understood and agreed that Operator has no rights of ownership or otherwise in, nor liabilities with respect to, any well (whether producing, plugged or abandoned) drilled on the property subject to any Lease identified in Exhibit B by Non-Operator or any other person, corporation or other entity prior to the date of this Agreement or, unless otherwise agreed to in writing by Non-Operator and Operator, in any well (whether producing, plugged or abandoned) drilled on the property subject to any other Lease prior to the - 7 - time it is deemed a Lease pursuant to Section 3.4 hereof; and to the extent it has the right to do so, Non-Operator may produce, rework, deepen and perform other operations on such wells for its sole account. 2.10 Operator and Non-Operator shall each have the right to transfer or otherwise assign working interests in any Well to any affiliate and to any limited partnership or other entity from which Operator or Non-Operator receives funds to drill the Well, provided, however, that each party must retain at least twenty percent (20%) of the working interests for which it participated hereunder in each Well (such retention may be by the direct ownership of such minimum working interest or indirectly by such party's ownership of an affiliate or such limited partnership or other entity which owns working interests in the Well) unless otherwise consented to by the other party, such consent not to be unreasonably withheld. 3. Title; Lease Status; Assignment by Non-Operator; AMI Election ------------------------------------------------------------- 3.1 Promptly after the execution of this Agreement, Non-Operator shall provide to Operator all information in its possession or subject to its control as to the title to the natural gas and oil underlying the property subject to the Leases identified in Exhibit B and the rights to explore for, develop, operate, produce and market such natural gas and oil including but not limited to the names and addresses of all owners of royalties and overriding royalties and the amounts of such royalties and overriding royalties. Additionally, at the time a copy of an agreement described in Section 3.4 hereof is sent to Operator, and thereafter, promptly after being requested to do so, Non-Operator shall provide to Operator all information in its possession or subject to its control as to the title to the natural gas and oil underlying the property subject to such agreement and the rights to explore for, develop, operate, produce and market such natural gas and oil. As to the title to the natural gas and oil underlying the property subject to the Leases and the right to explore for, develop, operate, produce and market such natural gas and oil, Non-Operator represents and warrants to and for the benefit of Operator and its successors and assigns that it will defend such title against every person, corporation or other entity claiming or to claim an interest therein by, through or under Non-Operator, or any member of Non-Operator, or any affiliate of any of them, but not otherwise. Prior to the drilling of a Well, the Operator shall obtain a report, prepared by an attorney or title insurance company licensed to practice or do business in Tennessee, as to whether the lessor(s) of the Lease, and each assignee of such lessor(s) including Non-Operator, are vested with good and marketable title to the rights to explore for, develop, operate, produce and market natural gas and oil on Well Acreage covered by the Lease on which the Well is to be drilled. Without limiting the foregoing, the report will cover, with respect to the Well Acreage covered by the Lease on which the Well is to be drilled, the ownership of the (i) oil and natural gas, (ii) working interests, (iii) royalties, (iv) overriding royalties and (v) other production payments, if any. Promptly after receipt of a report, Operator shall furnish a copy thereof to Non-Operator. If a report reveals defects in title, Operator may, in the exercise of its reasonable judgment, caused to be performed such curative work as Operator deems prudent (including obtaining pooling amendments or agreements) or may decide not to drill a Well on the Well Acreage subject to the report. Operator and Non-Operator shall each be responsible for, and pay, its Proportionate Share of the costs incurred to obtain such reports, and to perform curative work, including costs of abstracts, attorney's fees, title company charges, land broker charges and other related direct charges, provided, however, that Non-Operator shall not be responsible for, and shall not pay, any amount for services rendered by in-house counsel or other personnel of Operator with respect to title to any Well Acreage or any curative work relating thereto. - 8 - Except as to the warranty of title set forth in the preceding paragraph, neither Operator nor Non-Operator shall have any liability to the other for failure of title or any matter relating thereto. 3.2 Non-Operator hereby represents and warrants, as of the date hereof and continuing until March 31, 2005, to and for the benefit of Operator and its successors and assigns, that the Leases identified in Exhibit B are in full force and effect in accordance with their terms and that there are no defaults by lessee thereunder and that the lessee has no obligation under any such Lease to drill any well for the production of any methane or other gas from coal beds or coal mines and that all amendments to each such Lease are identified in Exhibit B and that all consents required under such Leases to permit Operator to perform its obligations, and exercise its rights, contemplated hereby have been obtained including consents to the assignment of such Leases and interests in the Wells and Well Acreage to Operator and to any affiliate of Operator or Non-Operator and to any limited partnerships and other entities from which Operator or Non-Operator receives funds to drill Wells, true and correct copies of such consents having been furnished by Non-Operator to Operator on or prior to the execution of this Agreement. Non-Operator shall not agree to any amendment or other modification of any Lease identified in Exhibit B without the prior written consent of Operator. Non-Operator shall be solely responsible for the payment of, and shall pay, all delay rentals, minimum royalties and other amounts required to be paid under the Leases to keep the Leases in full force and effect and upon request of Operator, Non-Operator shall provide evidence of such payment in such detail as Operator may reasonably request; Non-Operator shall be entitled to recoup such delay rentals, minimum royalties and/or other amounts as may be provided in the Lease and to the extent Operator receives funds from the sale or other disposition of natural gas and oil produced from the Wells which may be applied to such recoupment, it will pay such funds to Non-Operator. Operator and Non-Operator shall each pay its Proportionate Share of any shut-in royalties required to be paid under the Leases with respect to a Well. Additionally, Non-Operator shall comply with all other provisions of the Leases (except, subject to Section 2.3 hereof, the provisions to drill a minimum number of wells), and take all other actions to otherwise keep the Leases in full force and effect, with respect to the property subject thereto exclusive of Well Acreage. Promptly after receipt of any notice, or any document or other writing, from any lessor of a Lease, any governmental or regulatory authority or agency or any other person, corporation or authority relating to any Lease or Well or any activities conducted on the property subject to the Leases or relating to any other matter concerning the drilling, completion or operation of one or more Wells, or the transportation, compression, processing, marketing or sale of natural gas and/or oil produced therefrom, Non-Operator and Operator, as the case may be, shall provide the other with such notice, or document or other writing. 3.3 Upon payment by Operator of its Proportionate Share of the site fee for a Well pursuant to Section 2.7 hereof, the Non-Operator shall promptly execute and deliver to the Operator or its successors and assigns an Assignment in substantially the form attached hereto and made a part hereof as Exhibit D with respect to the Well Acreage on which the Well is to be drilled and the non-exclusive right to construct, maintain, repair and operate one or more lines, compressors, processing facilities and meters on the property subject to the Leases to transport, compress, process, measure, market and sell natural gas and oil produced from the Wells, which natural gas and oil shall be transported through the Coalfield Pipeline pursuant to a Gas Gathering Agreement between Operator and Coalfield Pipeline Company being executed contemporaneously with this Agreement. Unless otherwise agreed to by the Non-Operator, the Assignment shall except and reserve to the Non-Operator all interests and estates with respect to methane gas in coal beds and coal mines, together with the right to conduct operations on and drill through Well Acreage for the development, - 9 - extraction and processing of such methane gas so long as such operations and drilling do not adversely affect the operation of, or production from, any Well. In the Assignment and subject to the non-exclusive right described in the first sentence of this Section 3.3, Non-Operator shall further except and reserve unto itself all interests and estates in the Lease on which the Well is drilled, except as to the Well Acreage and as to all oil and gas formations from the surface to one hundred (100) feet below the deepest producing formation in the Well. 3.4 If the Non-Operator, either member of the Non-Operator or any affiliate of any of them acquires the right to drill one or more wells on the AMI pursuant to an agreement not identified in Exhibit B, the Non-Operator shall provide a copy of the agreement to the Operator promptly after the execution of such agreement. The Operator shall have the right, within thirty (30) days after receipt of the executed agreement, to notify the Non-Operator in writing that such agreement shall be deemed a Lease, subject to such conditions as may be set forth in the notice (including consents to assignment), for all purposes of this Agreement and Non-Operator shall not agree to any amendment or other modification of such Lease without the prior written consent of Operator. If such written notice is not given by the Operator within the thirty (30) day period, such agreement shall not be deemed a Lease and the Operator shall have no rights, or obligations, in regard to such agreement. Notwithstanding the foregoing, Operator shall have no right to have any acreage described in Exhibit B under the heading Excluded Acreage deemed subject to a Lease. With respect to the leases and other agreements ("Additional Potential Leases") described in Exhibit B under the heading Additional Potential Leases, on or before March 1, 2005, Non-Operator shall provide to Operator a copy of each such Additional Potential Lease. If Non-Operator desires to drill a natural gas and/or oil well on the property subject to an Additional Potential Lease, at least ninety (90) days prior to drilling such well, Non-Operator shall give written notice to Operator of such desire along with the proposed location, target formation and anticipated drilling date of the well (as well as copies of any amendment or other modification of such lease and of any consent to assignment required by such lease) and the Operator shall have the right to participate in such well for up to fifty percent (50%) of the working interests, if Operator elects, as provided below, to have the Additional Potential Lease and well deemed a Lease and Well hereunder. If Operator notifies Non-Operator in writing within thirty (30) days after receipt of the written notice from Non-Operator that Operator desires to participate in the well and sets forth, in such notice, its working interest participation, such well and Additional Potential Lease shall be deemed a Lease and a Well hereunder and Operator shall commence the drilling of the Well before the drilling date set forth in the notice from Non-Operator, it being understood and agreed that after Non-Operator gives the written notice to Operator set forth above, Non Operator shall not agree to any amendment or other modification of such Lease without the prior written consent of Operator. 3.5 The Operator agrees that for a period of seven (7) years after the execution of this Agreement, it will not acquire, other than as provided in this Agreement, the right to drill any wells or to mine any coal, or any interests in oil and gas or coal, on the AMI without the written consent of the Non-Operator. The provisions of this Section 3.5 shall survive the termination of this Agreement prior to the end of such seven (7) year period. 3.6 Notwithstanding anything to the contrary herein contained, all rights and obligations of Operator and Non-Operator hereunder relating to the Leases are subject to the terms and provisions of the Leases including, but not limited to, any rights of lessor or others to take over any Well to be plugged and abandoned. - 10 - 4. Drilling and Certain Related Procedures; Abandonment ---------------------------------------------------- 4.1 Other than the minimum number of Wells to test the Knox Formation, the Monteagle formation or any other formation set forth in the Leases, the Operator shall drill each Well to such formation as it shall designate, unless natural gas or oil is discovered in commercial quantities at a lesser depth which, in the opinion of the Operator, in its reasonable discretion, makes further drilling inadvisable to such target formations. If the Well is found to be commercially productive in the reasonable discretion and judgment of the Operator, the Operator shall complete the Well and if the Well produces natural gas, connect it to the Coalfield Pipeline, and if the Well produces oil, make appropriate arrangements for the prompt removal and sale of the oil produced from the Well. 4.2 The Operator shall provide or cause to be provided all materials, supplies, tools, labor and services required to drill and complete the Wells to be drilled pursuant to this Agreement through the wellhead, including, but not limited to, drilling rigs, casings, bits, drill pipe, and all water, power, fuel and lubricants required at the Well sites. In connection with the foregoing obligations, the Operator shall perform, or cause to be performed, with respect to the Wells, the following procedures, in accordance with industry custom and standard in the locality: (a) Grade and prepare the well location, including furnishing a suitable roadway thereto, if required, and following completion, backfill, grade and reseed the well location, all in accordance with the requirements of applicable law; (b) Install and cement the well casing in accordance with the specifications of the Operator and as required by state and federal law; (c) Electronically log and test the well in accordance with the specifications of the Operator to determine its productive capacity; (d) Perforate such casing opposite such formations as Operator may select in accordance with the specifications of the Operator; (e) Unless the Operator reasonably determines it is not necessary, stimulate one or more of the productive formations by means of nitrogen fracturing, hydrofracturing, acidizing, shooting, or other means in accordance with the specifications of the Operator, such stimulation and the extent and scope thereof to be designed by the Operator in accordance with generally accepted industry practices in the locality; (f) If necessary, install an oil and gas separator to separate any recoverable liquids from the natural gas, if such liquids are contained by the natural gas in commercial amounts, before such natural gas is delivered to the designated pipeline or compressing equipment, together with a tank to store any liquids so separated from the natural gas as required; (g) Use commercially reasonable efforts to obtain all rights of way and related surface rights and easements required, provide pipe for, and construct and place in operation, an appropriate gathering or other pipeline system to connect the Wells to the Coalfield Pipeline, provided, however, that to the extent Non-Operator or any of its members or any affiliate of any of them has such rights-of-way and related surface rights and easements, it shall grant Operator the non-exclusive right to use the same for such purpose; - 11 - (h) Install all drips and other devices in the gathering or other lines as shall be needed to ensure that all natural gas entering the lines shall have a moisture content no greater than the maximum allowable under current industry standards; and (i) In the event that Operator shall at any time determine that a Well is capable of producing oil in paying quantities, as either a Drilling Cost or an Operating Expense (i) install well pumping equipment following its completion in order to produce oil from the Well in an amount equal to its allowable or capacity production and (ii) provide pipe for, and construct and place in operation, an appropriate, if necessary, line to connect the Well to an oil transmission line (or, in the event that any oil produced is to be removed by tanker, construct a pipeline to an adequate tank battery at the designated pickup point). 4.3 Notwithstanding anything to the contrary contained in this Agreement, the Operator shall have the right to subcontract any part of the drilling, completion and operation of a Well, and any other work to be performed by Operator hereunder, to an affiliate of the Operator or any other party without the prior consent of the Non-Operator, provided, however, that no such subcontracting shall relieve the Operator of its obligations and responsibilities hereunder and any such subcontract must be made on commercially reasonable terms. The term "affiliate" as used in this Agreement shall mean any business entity which directly or indirectly through one or more intermediaries controls or is under the common control of the Operator or Non-Operator. 4.4 The Operator shall conduct all operations hereunder in a good and workmanlike manner. All materials and supplies to be provided shall be of good quality and suitable to the use to which they may be put and all equipment, appliances and tools shall be in operating order. Operator shall not be responsible for loss resulting from any latent defect in any material supplied by any third party or the negligence of any third party of any service. 4.5 In the event a Well is determined by the Operator, in its reasonable discretion, to be commercially unproductive following drilling to total depth and electronic logging thereof, and is thereby deemed a "Dry Hole," the Operator may notify the Non-Operator of such fact and of Operator's intention to plug and abandon, and the reasons for plugging and abandoning, the Well in accordance with the laws and regulations of the State of Tennessee. After sixty (60) days have expired from the date of mailing such notice, Operator may plug and abandon the Well and Operator and Non-Operator shall each pay its Proportionate Share of the costs of plugging and abandoning the Well. Notwithstanding the foregoing, in the event the Non-Operator desires that the Well not be plugged and abandoned, it shall, within said sixty (60) day period, serve upon Operator a written notice requesting the resignation of the Operator as to the Well. Such notice shall designate a new operator for the Well, and shall be accompanied by evidence of an operator's bond with respect to the Well. Such notice shall also be accompanied by a written agreement, signed by the Non-Operator, agreeing to assume the operation of the Well through the newly designated operator and relieving and discharging Operator of all further responsibility in connection with the operation or plugging and abandonment of the Well except for acts or activities occurring prior to the effective date of such notice. After the Well is placed under the bond of the new operator, Operator shall promptly transfer to Non-Operator, free or charge, all rights, titles and interests of Operator in and to the Well and the Well Acreage on which the Well is drilled. - 12 - 5. Other Operating Responsibilities of the Operator ------------------------------------------------ 5.1 In connection with the performance of its duties and responsibilities pursuant to the terms of this Agreement, Operator shall: (a) Keep the Leases free and clear of all labor, materials and other liens or encumbrances arising out of its operations; (b) Obtain and maintain at its own expense all worker's compensation coverage required by law with respect to its employees and employee liability insurance with a limit of $1,000,000 per occurrence, and require all of its subcontractors to obtain and maintain such coverage with respect to their employees; (c) Maintain in force at its own expense, with an insurance company or companies licensed to do business in Tennessee and rated A-, VII or better by A.M. Best, the following basic liability coverages (including independent contractor and completed operations and premises operations): comprehensive (including written contractual liability) general liability insurance and bodily injury insurance - $1,000,000 each occurrence and $1,000,000 aggregate; property damage liability (with deletion of underground property damage exclusion provisions ) - $1,000,000 each occurrence and $1,000,000 aggregate; and comprehensive auto liability and property damage in the same limits. The Operator shall also maintain an "umbrella" policy increasing the liability coverage hereinbefore set forth by the additional amount of $10,000,000. Upon receipt of a request of Non-Operator for a certificate of insurance, Operator shall request such a certificate and shall, upon receipt of the certificate, furnish the same to the Non-Operator. Non-Operator and its members, CNX Gas Company, LLC (and its members) and New River Energy, LLC (and its members), and CONSOL Energy, Inc., and their directors, officers and employees, shall be named as additional insureds under the policies and the policies shall provide that they may not be cancelled as to any coverage with respect to any of them, except after thirty (30) days' written notice to Non-Operator and CONSOL Energy, Inc. and the policies shall also provide a waiver of subrogation rights in favor of Non-Operator and its members, CNX Gas Company, LLC (and its members) and New River Energy, LLC (and its members) and CONSOL Energy, Inc., and their directors, officers and employees. In the event Operator is unable, or fails, to obtain or maintain any of the insurance coverage described above, Operator shall give Non-Operator notice thereof as soon as reasonably possible and in such event, Operator shall immediately cease conducting any activities on the property subject to the Leases until such time as Operator obtains such coverage unless such inability, or failure, results from insurance companies licensed to do business in Tennessee not generally offering such coverage. If Operator is unable, or fails, to obtain or maintain any of the insurance coverage described above for a period of thirty (30) days, Non-Operator shall have the right to immediately terminate the right of Operator to thereafter drill any Well and, except as set forth in the third paragraph of Section 2.8 hereof, the right or obligation of Operator to participate in any Well drilled thereafter, upon sending written notice to Operator unless such inability, or failure, results from insurance companies licensed to do business in Tennessee not generally offering such coverage or unless one or more subcontractors of Operator who have such coverage conduct, to the exclusion of Operator, all activities on the property subject to the Leases to fulfill all obligations of Operator hereunder to be performed on such property and Operator provides to Non-Operator within such thirty (30) day period a certificate of such insurance coverage of such subcontractor(s); - 13 - (d) Comply with all requirements of applicable federal, state and local laws, and all regulations pursuant thereto, including, but not limited to, (i) obtaining all permits and approvals required from any governmental or regulatory authority or agency for the drilling and other activities which are the subject hereof, (ii) duly complying with all environmental and other similar laws and regulations relating to well drilling operations and associated earthmoving activities and with the terms of any orders issued by any governmental or regulatory authority or agency having jurisdiction with respect thereto, and (iii) filing all reports required to be filed with any governmental or regulatory authority or agency in connection with the drilling and other activities which are the subject hereof. If Operator and/or any of its subcontractors repeatedly violate the material provisions of applicable federal, state or local law, or of regulations pursuant thereto, and fail to cure such violations in a timely manner, Non-Operator shall have the right to immediately terminate the right of Operator to thereafter drill any Well and, except as set forth in the third paragraph of Section 2.8 hereof, the right or obligation of Operator to participate in any Well drilled thereafter, upon sending to Operator written notice setting forth such violations. Fines imposed as a result of Operator and/or its subcontractors violating applicable federal, state or local law, or of regulations pursuant thereto, shall be payable solely by Operator unless such violations do not result from a breach by Operator of its obligations under paragraph (f) below, in which event Operator and Non-Operator shall each pay its Proportionate Share of such fines; (e) Comply with all of the provisions of the Leases, and take all actions required to keep the Leases in full force and effect, with respect to its operations hereunder; and (f) Perform its duties under this Agreement as a reasonable prudent operator, in a good and workmanlike manner, with due diligence and dispatch, in accordance with good oil field practice. Operator agrees to indemnify and hold Non-Operator, its employees, directors and affiliates harmless from any third-party suits, claims, damages or actions related to the performance of its duties hereunder except to the extent that such suits, claims, damages or actions arise from the negligence of Non-Operator. Except for the indemnification provided in this paragraph (f), no party shall be responsible to the other party for any special, indirect, consequential, lost profit or punitive damages regardless of the type of breach (financially related or non-financially related). 6. Marketing of Natural Gas and Oil -------------------------------- 6.1 The Operator shall use commercially reasonable efforts to sell, upon such terms and conditions as it shall in its reasonable discretion deem advisable, all natural gas and oil produced from the Wells, exclusive of any production which may be used in development and producing operations and any production lost due to loss or shrinkage or used in compression of natural gas or in preparing and treating oil for marketing. At least ten (10) days prior to entering into any agreement with respect to the sale of natural gas and/or oil produced from the Wells, Operator shall furnish a copy of such agreement to Non-Operator. Unless Non-Operator notifies Operator in writing, within ten (10) days after receipt by Non-Operator of such agreement, that Non-Operator elects, pursuant to Section 6.2 hereof, to receive in kind its Proportionate Share of the production from the Wells, as well as the overriding royalty of Non-Operator set forth in Section 2.6 hereof, Operator shall be authorized to sell Non-Operator's Proportionate Share of the production from the Wells, as well as such overriding royalty, pursuant to the terms and provisions of such agreement. Any such agreement shall be executed by Operator as agent for the Non-Operator, and the Non-Operator hereby appoints Operator as its agent and attorney-in-fact for such purpose and shall designate Operator as the payee of the gross proceeds - 14 - from the sale of natural gas and oil under such agreement so long as the Operator shall act as Operator hereunder. Notwithstanding anything to the contrary contained in this Agreement, unless agreed to otherwise by Non-Operator in writing, Operator shall have no authority to sell, and shall not sell, Non-Operator's Proportionate Share of the natural gas produced from the Wells except for a floating price determined daily or monthly based upon the commodity price of natural gas as reflected in the future prices on the New York Mercantile Exchange or a nationally recognized commodities index; Operator will use reasonable efforts to notify Non-Operator if it intends to sell Operator's Proportionate Share of the natural gas produced from the Wells at a price other than set forth above, the parties recognizing, however, that such notice may be given immediately before such sale because of market and other factors. Any authority delegated to the Operator to sell Non-Operator's Proportionate Share of the production from the Wells shall be limited to a period of time not in excess of the minimum needs of the industry and in no event for more than one year unless agreed to in writing by Non-Operator. Operator shall be solely responsible for the payment of any and all charges imposed by a pipeline or other transporter of natural gas which is to receive natural gas produced from the Wells at its connection with the Coalfield Pipeline and which arise from an imbalance between (i) quantities of natural gas produced from the Wells and nominated by Operator for delivery to such pipeline or other transporter and (ii) quantities of such natural gas actually delivered; provided, however, that Operator shall have no such responsibility, and Non-Operator shall bear its Proportionate Share of any and all such charges, if the imbalance results from "force majeure" (as such term is defined in Section 14.1 hereof) or any other cause except the negligence of Operator. 6.2 Notwithstanding anything to the contrary contained in this Agreement, the Non-Operator shall own its Proportionate Share of the Wells and the natural gas and oil which is produced therefrom, and shall have, and may exercise, at any time and from time to time, its right and privilege to receive in kind its Proportionate Share of the production from the Wells, as well as the overriding royalty of Non-Operator set forth in Section 2.6 hereof, and make a sale thereof for its own account, provided, however, that if Non-Operator exercises its right and privilege to take in kind, such exercise shall be for one hundred percent (100%) of its Proportionate Share of the natural gas production from the Wells, as well as the natural gas overriding royalty of Non-Operator set forth in Section 2.6 hereof and Non-Operator shall use its best efforts to actually take in kind one hundred percent (100%) of such natural gas production and overriding royalty and provided further, that Non-Operator shall be responsible for the payment of all costs and expenses incurred by Non-Operator, Operator or otherwise in connection with Non-Operator's receipt in kind and failure, if any, to take in kind one hundred percent (100%) of such natural gas production and overriding royalty. Additionally, if Non-Operator exercises its right and privilege to receive in kind its Proportionate Share of the natural gas production from the Wells, as well as the natural gas overriding royalty of Non-Operator set forth in Section 2.6 hereof, to the extent Operator has the right, whether exclusive or otherwise, to have natural gas produced from the Wells compressed and transported through the Coalfield Pipeline, such natural gas production and overriding royalty of Non-Operator shall be delivered by Operator into the Coalfield Pipeline on the same basis as all other natural gas production from the Wells. 6.3 Operator shall distribute to Non-Operator on a monthly basis Non-Operator's Proportionate Share of the Net Revenues from the Wells received by Operator and the overriding royalties payable to Non-Operator pursuant to Section 2.6 hereof unless Non-Operator receives in kind, as set forth in Section 6.2 hereof, its Proportionate Share of the production from the Wells and/or the overriding royalty of Non-Operator set forth in Section 2.6 hereof. 6.4 The balancing of the Proportionate Shares of Operator and Non-Operator of natural gas produced from the Wells, as well as the Overriding Royalty of Non-Operator taken in kind, shall be governed by the terms and provisions of the Gas Balancing Agreement attached hereto as Exhibit E and made a part hereof. - 15 - 7. Superintendence and Maintenance of the Wells; Operator's Fee and Other Charges ---------------------------------------------------------------- 7.1 In addition to its other obligations hereunder, the Operator, shall be responsible for superintendence and maintenance of the Wells, if productive. In particular, and without limiting the generality of the foregoing, the Operator shall take the following actions with respect to each Well: (a) The Well shall remain connected to its transmission, gathering or other pipeline system, as appropriate, at all times, except to the extent disconnection is required: (i) For repairs to the Well or associated facilities; (ii) To accommodate surface or other coal mining operations where the surface or other coal mining rights have priority over the oil and gas exploration and production rights; and (iii) To accommodate timbering operations where the timber rights have priority over the oil and gas exploration and production rights. (b) In the event the Well is disconnected for repairs, reconnection shall be made promptly following the completion of such repairs (after authorization from the Gas Purchaser, if required); (c) Appropriate shut-in pressure tests are conducted with respect to the Well; (d) All metering, valves and other wellhead equipment are checked regularly and maintained in good condition; and (e) The Well is kept in good condition for the production of natural gas and oil. 7.2 The number of employees required for the discharge of the Operator's superintendence and maintenance responsibilities hereunder and their selection and hours of labor shall be determined by the Operator, in its sole and absolute discretion. 7.3 In lieu of any direct charges by the Operator for the services of the Operator or any of its employees or subcontractors required for superintendence and maintenance of the Wells under this Agreement, if productive, and in lieu of any accounting, bookkeeping and distribution expenses, the Operator shall be entitled to receive payment from Non-Operator of its Proportionate Share of the rate of Two Hundred Twenty-Five Dollars ($225) - 16 - per month per Well (the "Operator's Fee"), commencing with the first month or part thereof that the Well is in production and continuing for each month thereafter whether or not the Well shall be in production, provided, however, that no Operator's Fee shall be charged for any month during which the Well is shut-in for the entire month for reasons other than repair or maintenance. Such amount is intended to compensate the Operator for the services supplied by Operator, its personnel and the personnel of any subcontractors engaged by Operator but excluding any allowance for materials, supplies, or the use of Operator's equipment. Notwithstanding the foregoing, in the event that it shall be necessary for Operator to incur unusual or extraordinary expenses in the operation of the Wells, such as in the case of a Well whose productivity of oil is such as to require intensive supervision, such additional expenses shall be deemed to be an Operating Expense. The Operator's Fee at the rate of Two Hundred Twenty-Five Dollars ($225) per month per Well shall be fixed at such amount until December 31, 2007. The Operator's Fee may be adjusted as of January 1, 2008 for the period beginning on such date and ending on December 31, 2008 and thereafter may be adjusted annually for the periods beginning January 1 of a year and ending December 31 of the same year. The adjustment shall be computed by multiplying the Operator's Fee currently in effect by the percentage increase or decrease, if any, recommended by the Council of Petroleum Accountants Societies ("COPAS") each year and the adjusted Operator's Fee shall be the Operator's Fee currently in use plus or minus the adjustment, provided, however, that the adjusted Operator's Fee shall never be less than Two Hundred Twenty-Five Dollars ($225) per month per Well. 8. Costs and Expenses; Plugging Reserve Account -------------------------------------------- 8.1 The Operator shall cause all Operating Expenses to be promptly paid and discharged and Non-Operator shall be responsible for payment of its Proportionate Share of all Operating Expenses. In the event the Operator shall have paid any Operating Expenses with respect to the Wells out of its own funds, Non-Operator's Proportionate Share of the amounts thereof shall be reimbursed by the Non-Operator to the Operator within thirty (30) days after receipt of a statement therefor to the extent Non-Operator's Proportionate Share of such Operating Expenses exceeds its Proportionate Share of the Net Revenues from the Wells received by Operator. Additionally, Non-Operator's Proportionate Share of the Operating Fee for the Wells shall be paid by the Non-Operator to the Operator within thirty (30) days after receipt of a statement therefore to the extent Non-Operator's Proportionate Share of the Operator's Fee for the Wells exceeds its Proportionate Share of the Net Revenues from the Wells received by Operator. Operator is authorized hereby to establish a reasonable reserve from the revenues of the Wells in order to defray the Operator's Fee and reasonably anticipated Operating Expenses associated with the Wells and to deposit the funds reserved in a separate and segregated interest-bearing reserve account (the "Operating Reserve Account"), provided, that the funds in the Operating Reserve Account (including accrued interest) shall not exceed Two Thousand Dollars ($2,000) for any Well or Fifty Thousand Dollars ($50,000) in the aggregate for all Wells. Non-Operator hereby grants unto Operator a security interest or lien and right to off-set in the revenues of the Wells to secure Operator in the payment of Operating Expenses and the Operator's Fee. 8.2 The Operator shall further pay promptly all charges for labor and materials which it incurs in performing its duties under this Agreement, whether or not the same are chargeable to the Non-Operator, and shall not, providing that all amounts due to Operator hereunder shall have been timely paid and shall not be in default in any respect, permit any liens for such labor -17 - and/or materials to be filed by any person against the Non-Operator's interests in the Wells or, if filed, shall take prompt action to have the same removed. 8.3 Notwithstanding anything to the contrary contained in this Agreement, if after a Well has been placed into production for natural gas and/or oil, the Operator shall reasonably determine that the Well has become incapable of producing natural gas and/or oil in commercial quantities, the Operator may notify the Non-Operator of the fact of such non-productivity and of Operator's intention to plug and abandon, and the reasons for plugging and abandoning, the Well in accordance with the laws and regulations of the State of Tennessee. After sixty (60) days have expired from the date of mailing such notice, Operator may plug and abandon the Well. Operator shall first utilize the funds in the Plugging Reserve Account (as defined in Section 8.4 hereof) to pay the costs of plugging and abandoning the Well. In the event the amounts in the Plugging Reserve Account are insufficient to pay all of the costs of plugging and abandoning the Well, then Operator shall invoice the Non-Operator for Non-Operator's Proportionate Share of the additional amounts (which shall be an Operating Expense) needed to pay such costs in full and the Non-Operator shall remit to Operator the Non-Operator's Proportionate Share of such additional amounts within thirty (30) days after receipt of an invoice from Operator therefor, it being understood and agreed that in no event will Non-Operator be responsible or liable for any costs to plug and abandon a Well beyond its Proportionate Share of such Well. Notwithstanding the foregoing, in the event the Non-Operator desires that the Well not be plugged and abandoned, it shall, within said sixty (60) day period, serve upon Operator a written notice requesting the resignation of the Operator as to the Well. Such notice shall designate a new operator for the Well, and shall be accompanied by evidence of an operator's bond with respect to the Well. Such notice shall also be accompanied by (i) a written agreement, signed by the Non-Operator, agreeing to assume the operation of the Well through the newly designated operator and relieving and discharging Operator of all further responsibility in connection with the operation or plugging and abandonment of the Well except for acts or activities occurring prior to the effective date of such notice and (ii) payment to Operator and other working interest owners of their Proportionate Share of the then fair market value of the salvageable casing, tubing and fixtures of the Well. After the Well is placed under the bond of the new operator, Operator and the other working interest owners shall promptly transfer to Non-Operator all of their rights, titles and interests in and to the Well and the Well Acreage on which the Well is drilled and shall promptly transfer to the new operator the Non-Operator's Proportionate Share of the funds in the Plugging Reserve Account attributable to the Well. 8.4 (a) Operator shall have the right to retain as an Operating Expense, on a monthly basis, a portion of the Net Revenues (the "Plugging Funds") for the payment of the anticipated future costs of plugging and abandoning Wells when the plugging and abandonment of one or more Wells becomes necessary in the opinion of the Operator, in its reasonable discretion. The Plugging Funds shall be placed in a separate and segregated interest-bearing reserve account for the Wells (the "Plugging Reserve Account"). The Operator shall maintain an accounting system that will allow identification of the Plugging Funds which have been paid in for each Well, provided, however, that Non-Operator's Proportionate Share of the Plugging Funds for any Well may be used to pay Non-Operator's Proportionate Share of the costs of plugging and abandoning any other Well. The amount of the Plugging Funds to be retained.monthly shall be determined by the Operator, acting in good faith, taking into account the following factors: (i) The anticipated life of the Well; - 18 - (ii) The anticipated costs of plugging and abandoning the Well in accordance with all applicable statutes, codes and regulations at the end of the useful life of the Well; (iii) The effect of compounded interest upon amounts deposited into the Plugging Reserve Account for the Well; and (iv) Any other factors which Operator reasonably deems relevant. (b) As of the date of this Agreement: (i) Operator has determined that after the first year of production from a Well four percent (4%) of the monthly Net Revenues from such Well, not to exceed Two Hundred Dollars ($200) for any month, will be placed in the Plugging Reserve Account; and (ii) Operator has determined that such amount will be placed into the Plugging Reserve Account until the principal sum (including accrued interest) is equal to Ten Thousand Dollars ($10,000) for each Well. The Operator reserves the right to revise the monthly withholding amounts and/or the total amounts set forth above when, acting in good faith, the Operator determines, taking into account the factors set forth in Section 8.4(a) above, that such amounts must be adjusted upward or downward in order to provide for the payment in full of the future plugging and abandonment costs of the Wells. (c) Should the Operator determine, in its reasonable discretion, that at the time it becomes necessary to plug and abandon Wells, insufficient funds for such abandonment and plugging are on deposit in the Plugging Reserve Account, the Operator shall invoice the Non-Operator for its Proportionate Share of the additional sums needed to plug and abandon the Wells, and such additional sums shall be considered Operating Expenses under the terms of this Agreement, and Non-Operator shall pay such invoice within thirty (30) days after receipt. Should the Operator determine, in its reasonable discretion, that funds, including accrued interest, in the Plugging Reserve Account exceed the amount necessary to plug and abandon the Wells, the Operator shall, upon such determination, refund to the Non-Operator and other working interest owners their Proportionate Shares of such excess funds, provided, however, that no refund will be made to the extent it would reduce the funds, including accrued interest, in the Plugging Reserve Account below Ten Thousand Dollars ($10,000) for any Well. (d) Non-Operator's Proportionate Share of the interest accrued on the Plugging Reserve Account shall be allocated as income to the Non-Operator. 9. Additional Operations --------------------- 9.1 Without the prior consent of the Non-Operator, no expenditure in excess of Ten Thousand Dollars ($10,000) shall be made relating to any Well in which Non-Operator has a working interest except the initial drilling and completion of such Well. - 19 - 9.2 Notwithstanding the foregoing, the Operator shall be authorized, without being required to obtain the consent of the Non-Operator, in the case of explosion, fire, flood, or discharge or release of any hydrocarbon or other hazardous substance which requires immediate remediation, or other sudden emergency whether of the same or different nature, to take such steps and incur such expenses as in its opinion are required to deal with the emergency and to safeguard life and property. In such event, the Operator shall promptly notify the Non-Operator of the matter which gave rise to the expenditures made by the Operator and account to the Non-Operator for all such expenditures and such expenditures, once accounted for, shall be deemed to be an Operating Expense unless the matter which gave rise to the expenditure resulted from the negligence of the Operator. 9.3 Notwithstanding the foregoing, in the event that Operator shall propose to make an expenditure with respect to a Well in excess of the amount specified in Section 9.1 hereof and in the event that Non-Operator owns less than a fifty percent (50%) working interest in the Well, such proposed expenditure may nevertheless be made and any party advancing any funds attributable to the interest of Non-Operator may recoup an amount equal to two hundred percent (200%) of such funds from the Net Revenues of the Well attributable to the interest of Non-Operator before any further distributions shall be made from the Net Revenues of the Well to Non-Operator. 10. Non-Operator's Access; Audit ---------------------------- 10.1 The Non-Operator shall have access to the Wells and to any information in the possession of the Operator pertaining to the Wells, and shall be entitled to inspect and observe operations of every kind and character upon the property covered by the Lease. 10.2 Upon reasonable notice to the Operator and at times mutually convenient to the parties hereto, the Non-Operator shall also have access to, and is entitled to receive copies of, the records and other documents on file at the Operator's office relating to the drilling, completion and operation of the Wells, including all Well logs and production records. In addition, during the drilling and completion of a Well, such number (as the Non-Operator or its designated agent may reasonably request) of copies of drilling reports, logs, completion reports and other data produced in connection with such activities shall be made available and provided to the Non-Operator or such agent, as they are produced or promptly thereafter. 10.3 The Non-Operator shall have the right, at its own cost and expense and not more frequently than once in each calendar year, to have an independent audit made of the books and records of Operator to verify, for the preceding two (2) calendar years, all Drilling Costs and Operating Expenses charged to Non-Operator, the production of natural gas and oil from the Wells and the proceeds of the sale or other disposition of such natural gas and oil production, the royalties and overriding royalties paid with respect to such production and the recoupment of delay rentals, minimum royalties and other amounts as set forth in Section 3.2 hereof and the funds (including accrued interest) in the Operating Reserve Account and the Plugging Reserve Account. 11. Term and Termination -------------------- 11.1 This Agreement shall commence upon the effective date hereof and shall remain in full force and effect with respect to each Well until such time as such Well is abandoned and plugged in accordance with the laws and regulations of the State of Tennessee. - 20 - 11.2 In the event that the Non-Operator shall, in good faith, determine that Operator is in substantial or material breach of the duties and obligations imposed upon Operator by this Agreement, then the Non-Operator shall give Operator written notice thereof specifying the event or events of default to be cured by Operator. In the event that Operator has substantially or materially breached the duties and obligations imposed upon the Operator by this Agreement, Operator shall then have a period of ninety (90) days after receipt of said written notice of default to cure such breach or default, or in which to implement a plan of action which, if taken to its natural conclusion and continuously prosecuted, would cure such breach or default. In the event that Operator cures such breach or default or implements a plan of action which, if taken to its natural conclusion and continuously prosecuted, would cure such breach or default, the Non-Operator shall not have the right to substitute a new operator. In the event that Operator upon the expiration of the aforesaid ninety (90) day cure period has not cured such breach or default, and/or has not implemented a plan of action which, if taken to its natural conclusion and continuously prosecuted, would cure such breach or default or if Operator has failed to continuously prosecute such plan of action, the Non-Operator may substitute a new operator. 11.3 After the Initial Period and, if applicable, after the Option Period, Operator shall have the right to resign as Operator hereunder on ninety (90) days' written notice to the Non-Operator, in which event the Non-Operator shall appoint a new operator, provided, however, that if Non-Operator is unable, after having made reasonable efforts, to appoint a new operator within such ninety (90) day period, such period shall be extended for such additional time as Non-Operator continuously and diligently seeks the appointment of a new operator. Upon the effective date of such resignation, Operator shall have no further responsibility hereunder and shall, except for acts or activities occurring prior to such effective date, have no liability for any loss to the Non-Operator as a result of Operator's resignation. 11.4 In the event that Operator shall, for any reason, cease to be the Operator hereunder, the Non-Operator shall promptly furnish a bond in form and substance satisfactory for the operation of natural gas and oil wells and shall cause the Wells to be transferred and placed under Non-Operator's bond, or the Non-Operator may designate a properly bonded new operator. Promptly after all Wells are placed under the bond of Non-Operator or the new operator, Operator shall transfer to the Non-Operator or the new operator, as the case may be, all funds in the Operating Reserve Account and the Plugging Reserve Account. Thereafter, Operator shall be deemed a non-operator hereunder with respect to the interests in the Wells owned by it, or by any affiliate or by any limited partnership or other entity from which Operator received funds to drill Wells, with all the rights and liabilities of a non-operator hereunder relating to such interests, provided, however, that neither Operator nor any such affiliate, limited partnership or other entity shall have any right to participate in any Wells drilled thereafter, although Operator may have the obligation under Section 2.8 hereof to participate in one or more such Wells. Additionally, if Operator is no longer the operator hereunder, Non-Operator or the new operator, as the case may be, shall have no obligation or other liability to account for any matter relating to the Wells to any affiliate of Operator or to any limited partnership or other entity from which Operator received funds to drill Wells, or to distribute to any such affiliate, limited partnership or other entity, any Net Revenues from such Wells attributable to the interests in such Wells of any such affiliate, limited partnership or other entity. Non-Operator or the new operator, as the case may be, shall account for matters relating to the Wells only to Operator and shall - 21 - make distributions of such Net Revenues only to Operator, who in turn shall account, and make distributions of such Net Revenues, to such affiliates, limited partnerships and other entities. 12. Contract Not Assignable ----------------------- 12.1 Except as set forth in Section 2.10 hereof, neither the Operator nor the Non-Operator shall assign its obligations or rights hereunder but Operator shall have the right to subcontract for the performance of all or any portion of the work to be performed by Operator hereunder. 13. Relationship; Internal Revenue Code Election -------------------------------------------- 13.1 None of the rights, duties, or obligations of the parties hereto or terms hereof shall be construed as creating a joint venture, a partnership, nor any other legal entity whereby one party is responsible individually for all debts, liabilities or charges incurred in connection with the drilling, completion, operation or abandonment of the Wells or any other activities contemplated hereby; each of the parties hereto shall be responsible only for its Proportionate Share of such debts, liabilities or charges. 13.2 The parties by their execution of this Agreement hereby assert that this Agreement and the activities contemplated hereby shall not constitute a partnership under the Internal Revenue Code of 1986, as amended (the "Code"); nevertheless, the parties elect, under the authority of Section 761 of the Code, to be excluded from the application of all of the provisions of Subchapter K of Chapter I of Subtitle A of the Code ("Subchapter K"). If future income tax laws of the United States, or the present or future income tax laws of Tennessee, contain provisions similar to those contained in Subchapter K under which a similar election is permitted, the parties agree that such election shall be exercised. The Non-Operator authorizes and directs the Operator to execute on behalf of Non-Operator such evidence of this election as may be required by the United States Treasury Department or the Internal Revenue Service, including specifically, but not by way of limitation, all of the returns, statements and data required by Treasury Regulations Section 1.761. Should there be any requirement that any party affected hereby give further evidence of this election, such party shall execute such documents and furnish such other evidence as may be required by the Internal Revenue Service as may be necessary to evidence this election. No party shall give any notices or take any other action inconsistent with the election made hereby. Should a gas imbalance arise where a party does not take its Proportionate Share of production from a Well and another person, corporation or other entity takes more than its Proportionate Share of such production, then the party which does not take its Proportionate Share shall use the "cumulative gas balancing method" as described in Treasury Regulation Section 1.761-2(d) for purposes of accounting for such imbalance. The parties agree to report their shares of the items of income, deductions and credits associated with the Wells in a manner consistent with exclusion from the application of the provisions of Subchapter K. 14. Force Majeure ------------- 14.1 If any party is rendered unable, wholly or in part, by force majeure to carry out its obligations under this Agreement, other than the obligation to make money payments or furnish security, that party shall give to the other party prompt written notice of the force majeure with reasonably full particulars concerning it; thereupon, the obligations of the party giving the notice, so far as they are affected by the force majeure, shall be suspended during, but no longer than, the continuance of the force majeure. The term "force majeure", as here employed, shall mean an act of God, strike, lockout, or - 22 - other industrial disturbance, act of the public enemy, war, blockade, public riot, lightning, fire, storm, flood or other act of nature, explosion, governmental action, governmental delay, restraint or inaction, unavailability of equipment, and any other cause, whether of the kind specifically enumerated above or otherwise, which is not reasonably within the control of the party claiming suspension; provided, however, that unavailability of equipment shall not constitute "force majeure" for purposes of this Agreement with respect to the drilling, as set forth in Section 2.8 hereof, of the minimum number of Wells set forth in the Leases to keep such Leases in full force and effect during the Initial Period and, if applicable, during the Option Period. The affected party shall use all reasonable diligence to remove the force majeure situation as quickly as practicable. 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 by the party involved, contrary to its wishes; how all such difficulties shall be handled shall be entirely within the discretion of the party concerned. 15. Notices ------- 15.1 All notices or other correspondence required or made necessary by the terms of this Agreement shall be in writing and shall be considered as having been given to a party (i) if given by telecopy, at the time the telecopy is transmitted to the following telecopier numbers and the appropriate answer back is received or receipt is otherwise confirmed, (ii) if given by mail, two (2) business days after being mailed by registered or certified mail, postage prepaid, to the following addresses, or (iii) if given by any other means (including but not limited to overnight delivery), when delivered at the following addresses: (a) Operator: Atlas America, Inc. 311 Rouser Road Moon Township Coraopolis, PA 15108 Attention: Frank Carolas Telecopier No.: (412) 262-3927 (b) Non-Operator: Knox Energy, LLC P.O. Box 947 Bluefield, VA 24605 Attention: Claude Morgan Telecopier: (276) 988-1076 with a copy to: Knox Energy, LLC 132 Mitchell Road Oak Ridge, TN 37830 Telecopier No.: (865) 481-3896 - 23 - Each party shall have the right to change its address at any time, and from time to time, by giving written notice thereof to the other party. 16. Governing Law ------------- 16.1 This Agreement shall be governed by and construed in accordance with the laws of the Commonwealth of Pennsylvania, without giving effect to the principles of conflicts of laws of the Commonwealth of Pennsylvania, provided, however, that as to real property issues, this Agreement shall be governed by and construed in accordance with the laws of the State of Tennessee, without giving effect to the principles of conflicts of laws of the State of Tennessee. 17. Successors in Interest ---------------------- 17.1 Each and all of the covenants, agreements, terms and provisions of this Agreement shall be binding on and inure to the benefit of the parties hereto and their successors and assigns. 18. Integration; Amendment; Interpretation -------------------------------------- 18.1 This Agreement constitutes the entire agreement between the parties pertaining to the subject matter hereof and supercedes all prior and contemporaneous agreements and understandings of the parties in connection herewith. Any amendment or supplement made hereto shall be in writing and signed by all parties. The headings contained in this Agreement are for reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement. Terms such as "herein", "hereby", "hereto", "hereunder", and "hereof" refer to this Agreement as a whole. 19. Severability ------------ 19.1 If any term or other provision of this Agreement is invalid, illegal or incapable of being enforced by any rule of law or public policy, all other terms and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any manner adverse to any party. Upon any binding determination that any term or other provision is invalid, illegal or incapable of being enforced, the parties hereto shall negotiate in good faith to modify this Agreement so as to effect the original intent of the parties as closely as possible in an acceptable and legally enforceable manner, to the end that the transactions contemplated hereby may be completed to the fullest extent possible. 20. Waivers ------- 20.1 No waiver by any party of any default hereunder by any other party shall operate as a waiver of any other default or of the same default on a subsequent occasion. No failure to exercise, and no delay in exercising, by any party of any power, remedy or right shall operate as a waiver thereof, nor shall any single or partial exercise of any power, remedy or right preclude other or further exercise thereof or the exercise of any other power, remedy or right. All powers, rights and remedies may be asserted concurrently, cumulatively, successively or independently from time to time. - 24 - 21. Further Assurances ------------------ 21.1 The parties agree to promptly execute and deliver, or cause to be executed and delivered, at such times as shall be reasonably requested, any additional instrument or take any further action as may be reasonably necessary or appropriate that any party may reasonably request for the purpose of carrying out the transactions contemplated by, and the purposes and intents of, this Agreement. 22. Attorneys' Fees --------------- 22.1 In any dispute among the parties hereto arising under this Agreement, the prevailing party shall be entitled to recover from the other party its reasonable attorney fees and other reasonable costs of litigation in addition to all other remedies. 23. Public Statements ----------------- 23.1 Neither party shall make any statements or releases to the general public relating to this Agreement or the activities conducted pursuant hereto without the permission of the other party, not to be unreasonably withheld, except (i) in filings required of either Operator or its parent, Resource America, Inc., or any affiliate of either of them, under federal securities laws, rules and regulations, or under the laws, rules, regulations or ordinances of the United States or any other jurisdiction, or by any federal, state or local governmental or regulatory authority or agency, (ii) disclosure required by the rules, regulations or policies of any stock exchange or automated interdealer quotation system on which any securities of Operator or the parent of Operator, or any affiliate of either of them, may be listed, or (iii) if compelled to do so in any legal proceeding or otherwise. 24. Counterpart; Fax ---------------- 24.1 This Agreement may be executed in any number of counterparts, each of which shall be deemed an original and all of which together shall constitute but one and the same agreement. It is agreed by the parties that facsimile signature pages signed by the parties shall be binding to the same extent as original signature pages. [REMAINDER OF PAGE INTENTIONALLY LEFT BLANK] - 25 - IN WITNESS WHEREOF, the parties have caused their names to be signed hereto by their proper officers duly authorized all as of the day and year first hereinabove written. OPERATOR: WITNESS: ATLAS AMERICA, INC., a Pennsylvania corporation ___________________________ By:__________________________________ Name:________________________________ Title:_______________________________ NON-OPERATOR: KNOX ENERGY, LLC By its members: WITNESS: CNX Gas Company, LLC, a Virginia limited liability company ___________________________ By:__________________________________ Name:________________________________ Title:_______________________________ WITNESS: New River Energy, LLC, a Tennessee limited liability company ___________________________ By:__________________________________ Name:________________________________ Title:_______________________________ - 26 - EX-14 17 ex10-14.txt EXHIBIT 10.14 EXHIBIT 10.14 ATLAS AMERICA SERIES 26-2005 L.P. DEALER-MANAGER AGREEMENT FOR 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..............................................................2 4. Compensation and Fees.................................................................................3 5. Covenants of the Managing General Partner.............................................................5 6. Representations and Warranties of the Dealer-Manager..................................................5 7. State Securities Registration........................................................................10 8. Expense of Sale......................................................................................10 9. Conditions of the Dealer-Manager's Duties............................................................11 10. Conditions of the Managing General Partner's Duties..................................................11 11. Indemnification......................................................................................11 12. Representations and Agreements to Survive Delivery...................................................12 13. Termination..........................................................................................12 14. Notices..............................................................................................13 15. Format of Checks/Escrow Agent........................................................................13 16. Transmittal Procedures...............................................................................13 17. Parties..............................................................................................14 18. Relationship.........................................................................................14 19. Effective Date.......................................................................................14 20. Entire Agreement, Waiver.............................................................................14 21. Governing Law........................................................................................14 22. Complaints...........................................................................................14 23. Privacy..............................................................................................15 24. Anti-Money Laundering Provision......................................................................15 25. Acceptance...........................................................................................15
Exhibit A - Escrow Agreement Exhibit B - Selling Agent Agreement i ANTHEM SECURITIES, INC. DEALER-MANAGER AGREEMENT (Best Efforts) RE: ATLAS AMERICA SERIES 26-2005 L.P. --------------------------------- Anthem Securities, Inc. P.O. Box 926 Coraopolis, Pennsylvania 15108-0926 Gentlemen: The undersigned, Atlas Resources, Inc., which is referred to as the "Managing General Partner," on behalf of Atlas America Series 26-2005 L.P., which is referred to as the "Partnership," is an offering of up to 1,400 investor general partner interests and limited partner interests, which are referred to as "Units," in the Partnership. The Managing General Partner on behalf of the Partnership hereby confirms its agreement with you, as Dealer-Manager, as follows: 1. DESCRIPTION OF PROGRAM AND UNITS. (a) Atlas Resources, Inc., a Pennsylvania corporation, is the sole Managing General Partner of the Partnership, which was formed as a limited partnership under the Delaware Revised Uniform Limited Partnership Act. (b) The Units being offered and the offering are described in the Private Placement Memorandum dated July 15, 2005, which is referred to as the "Private Placement Memorandum." The Managing General Partner has packaged each numbered Private Placement Memorandum, together with a copy of each item of sales materials that it has approved for use with potential investors in the Partnership, which are collectively referred to as the "Sales Literature," in kits, which are referred to as the "Private Placement Memorandum Kits." Terms defined in the Private Placement Memorandum and not otherwise defined in this Agreement shall have the meanings set forth in the Private Placement Memorandum. (c) The Partnership will issue and sell the Units at a price of $25,000 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 the Partnership by its Offering Termination Date as described in the Private Placement Memorandum (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 the Partnership will be as described in the Private Placement Memorandum. Also, the maximum subscription proceeds must not exceed $35 million. The Managing General Partner will notify you and the "Selling Agents," as defined below, of the Initial Closing Date for the Partnership. The Managing General Partner, its officers, directors, and affiliates may buy, for investment purposes only, the number of Units equal to the minimum subscription proceeds of $2,000,000 required for the Partnership to begin operations. 1 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 Units have not been and will not be registered with the Securities and Exchange Commission, which is referred to as the "Commission." So far as is under the control of the Managing General Partner the Units will be offered and sold in reliance on the exemption provided by Regulation D, which is referred to as "Regulation D," promulgated under Section 4(2) of the Securities Act of 1933, as amended, which is referred to as the "Act." (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 Regulation D and any exemptions under 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 the Partnership, which is referred to as the "Partnership Agreement," the form of which is included as Exhibit (A) to the Private Placement Memorandum, 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 the Partnership or of any jurisdiction to the laws of which the Partnership is subject. (d) The Partnership was duly formed under the laws of the State of Delaware and is 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 Private Placement Memorandum. The 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 Private Placement Memorandum, 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 Private Placement Memorandum, 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 Partnership and gives you the exclusive right during the offering period as described in the Private Placement Memorandum to solicit subscriptions for the Units on a "best efforts" basis in all states. (b) 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." 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. 2 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 the Partnership 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 1.5% nonaccountable marketing expense fee; and (iv) a .5% nonaccountable due diligence fee. (b) All or a portion of the Sales Commissions, the nonaccountable due diligence fee and the nonaccountable marketing expense fee may be reallowed to the Selling Agents. Additionally, you may reduce the 1.5% nonaccountable marketing expense fee payable to the Selling Agents as set forth in Section 2(a)(iii) of the Selling Agent Agreement and you may reduce the .5% nonaccountable due diligence fee payable to the Selling Agents as set forth in Section 2(a)(ii) of the Selling Agent Agreement. Of the 2.5% Dealer-Manager fee, some or all may be reallowed to the wholesalers for subscriptions obtained through their efforts. You shall retain any of the 2.5% Dealer-Manager fee, the Sales Commissions, the 1.5% nonaccountable marketing expense fee and the .5% nonaccountable due diligence fee not reallowed to the Selling Agents or the wholesalers. (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 1.5% nonaccountable marketing expense fee, and the .5% nonaccountable due diligence fee 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 1.5% nonaccountable marketing expense fee, and the .5% nonaccountable due diligence fee which shall be paid to you. No more than 10% of the total Units offered shall be sold in the Partnership with the discounts described above. (d) As an additional incentive, to the extent permitted by applicable law and subject to the receipt of the minimum subscription proceeds as described in Section 4(e) of this Agreement, each broker/dealer, including you and the Selling Agents, which has one or more registered representatives and/or principals who sell at least six Units each in the Partnership , including Units with discounted prices, shall share in payments from the Managing General Partner equal to 1% of the Partnership's production revenues less the related operating costs, administrative costs, direct costs, and other costs not specifically allocated. 3 A broker/dealer's participation in these payments shall be in the ratio which the total amount of Units sold by all of the broker/dealer's registered representatives and/or principals who sell at least six Units each in the Partnership bears to the total number of Units sold by all registered representatives and/or principals (including registered representatives and principals of the Dealer-Manager) who sell at least six Units each in the Partnership. The portion of these payments attributable to Units sold by the Selling Agents shall be reallowed by you to the qualifying Selling Agents. These payments shall be made quarterly. (e) Pending receipt and acceptance by the Managing General Partner of the minimum subscription proceeds of $2,000,000 in the Partnership, excluding the subscription discounts set forth in Section 4(c) of this Agreement, all proceeds received by you from the sale of Units in the 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 the Partnership, as described in Section 1 of this Agreement, the offering of Units in the Partnership shall be terminated, in which event: (i) the 2.5% Dealer-Manager fee, the 7% Sales Commission, the 1.5% nonaccountable marketing expense fee, and the .5% nonaccountable due diligence fee 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 (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. (f) Except as otherwise provided below, the fees 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 Partnership and accepted by the Managing General Partner; and (ii) the Partnership's subscription proceeds have been released from the escrow account to the Managing General Partner. You shall reallow to the Selling Agents and the wholesalers their respective fees and Sales Commissions as set forth in Section 4(b) of this Agreement. Thereafter, your fees and Sales Commissions shall be paid to you approximately every two weeks until the Offering Termination Date for the Partnership. All your remaining fees and Sales Commissions shall be paid by the Managing General Partner no later than fourteen business days after the Offering Termination Date for the Partnership. 4 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 Private Placement Memorandum Kit and all amendments or supplements to the Private Placement Memorandum. (b) If any event affecting the 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 Private Placement Memorandum, 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 Private Placement Memorandum 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 Private Placement Memorandum, 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 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 by you 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 Private Placement Memorandum shall not result in the following: (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 other instrument to which you are a party; or (ii) any violation of any order applicable to you of any court or any federal or state regulatory body or administrative agency having jurisdiction over you or your affiliates. (d) You are not subject to any disqualification described in Rule 505(b)(2)(iii) of Regulation 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 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 Private Placement Memorandum. 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. 5 (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 Regulation D, insofar as Regulation D 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 Regulation D, 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, and 2750, and specifically you agree as set forth below. (i) You agree to advise the Managing General Partner in writing of each state 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 state 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: (1) has been qualified in the state; (2) is exempt from the qualification requirements imposed by the state; or (3) the qualification is otherwise not required. (ii) Units shall not be offered and/or sold by you or the Selling Agents by means of any form of general solicitation or general advertising, including, but not limited to, the following: (1) any advertisement, article, notice, or other communication published in any newspaper, magazine, or similar media or broadcast over television or radio; (2) any seminar or meeting whose attendees have been invited by any general solicitation or general advertising; or (3) any letter, circular, notice or other written communication constituting a form of general solicitation or general advertising. (iii) You agree and shall require any Selling Agent to agree to provide each offeree with the following: (1) a complete Private Placement Memorandum Kit, which includes a numbered copy of the Private Placement Memorandum, all exhibits incorporated in the Private Placement Memorandum and, without exception, all of the Sales Literature; and (2) any numbered supplement or amendment to the Private Placement Memorandum as set forth in (iv) below. Also, each Private Placement Memorandum Kit includes a copy of the following Sales Literature: (1) a flyer entitled "Atlas America Series 26-2005 L.P."; 6 (2) an article entitled "Tax Rewards with Oil and Gas Partnerships"; (3) a brochure of tax scenarios entitled "How an Investment in Atlas America Series 26-2005 L.P. can Help Achieve an Investor's Tax Objectives"; (4) a brochure entitled "Investing in Atlas America Series 26-2005"; (5) a booklet entitled "Outline of Tax Consequences of Oil and Gas Drilling Programs"; (6) a brochure entitled "The Appalachian Basin: A Prime Drilling Location Which Commands a Premium"; (7) a brochure entitled "Investment Insights - Tax Time"; (8) a brochure entitled "Frequently Asked Questions"; (9) a brochure entitled "AMT - A Little History and Reducing AMT through Natural Gas Partnerships"; (10) a brochure entitled "The Drilling Process"; and (11) possibly other supplementary materials. Further, you and the Selling Agents shall keep file memoranda indicating by number to whom each Private Placement Memorandum Kit, including without exception, the Sales Literature, and supplement or amendment to the Private Placement Memorandum was delivered. (iv) When any supplement or amendment to the Private Placement Memorandum is prepared and delivered to you by the Managing General Partner, you agree and shall require any Selling Agent to agree as follows: (1) to distribute each supplement or amendment to the Private Placement Memorandum, identified by number, to every person who has previously received a Private Placement Memorandum Kit from you and/or the Selling Agent; (2) to include each supplement or amendment in all future deliveries of any Private Placement Memorandum Kit; and (3) to keep file memoranda indicating to whom each supplement or amendment was delivered. (v) In connection with any offer or sale of the Units, you agree and shall require any Selling Agent to agree, to the following: (1) to comply in all respects with statements set forth in the Private Placement Memorandum, the Partnership Agreement, and any supplements or amendments to the Private Placement Memorandum; 7 (2) not to make any statement inconsistent with the statements in the Private Placement Memorandum, the Partnership Agreement, and any supplements or amendments to the Private Placement Memorandum; (3) not to make any untrue or misleading statements of a material fact in connection with the Units; and (4) not to provide any written information, statements, or sales materials other than the Private Placement Memorandum, the Sales Literature, and any supplements or amendments to the Private Placement Memorandum unless approved in writing by the Managing General Partner. (vi) You and the Selling Agents shall advise each offeree of Units in the Partnership at the time of the initial offering to him that the Partnership and the Managing General Partner shall during the course of the offering and a reasonable time before sale accord him the opportunity to ask questions and receive answers concerning the terms and conditions of the offering and to obtain any additional information, to the extent possessed by the Partnership or the Managing General Partner or obtainable by either of them without unreasonable effort or expense, that is necessary to verify the accuracy of the information contained in the Private Placement Memorandum. (vii) Before the sale of any of the Units, you and the Selling Agents shall make reasonable inquiry to determine if the offeree is acquiring the Units for his own account or on behalf of other persons, and that the offeree understands the limitations on the offeree's disposition of the Units set forth in Rule 502(d) of Regulation D. This includes a determination by you and the Selling Agents that the offeree understands that he must bear the economic risk of the investment for an indefinite period of time because the Units have not been registered under the Act and, thus, cannot be sold unless the Units are subsequently registered under the Act or an exemption from registration under the Act is available. (viii) Before the sale of any of the Units you and the Selling Agents shall have reasonable grounds to believe that each subscriber is an "accredited investor" as that term is defined in Rule 501(a) of Regulation D. (ix) Units shall not be sold by you or the Selling Agents to anyone whom you or the Selling Agent reasonably believes is not an accredited investor. (x) 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: (1) the Selling Agents comply with all the provisions of Regulation D, 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; 8 (2) the prospective purchasers meet the suitability requirements set forth in the Private Placement Memorandum, the Subscription Agreement, and this Agreement; and (3) the prospective purchasers properly complete the following forms, which will be included in the Partnership's subscription packet as exhibits to the Private Placement Memorandum: (A) the Subscription Agreement and Annex A attached to the Subscription Agreement [Exhibit (I-B)]; and (B) the Execution Page and Purchaser Questionnaire [Exhibit (C)]; together with any additional forms provided in any supplement or amendment to the Private Placement Memorandum, 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 packets shall be transmitted as set forth in Section 16 of this Agreement. (xi) 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. (xii) You agree and covenant that: (1) the representations and warranties you make in this Agreement are and shall be true and correct at the applicable closing date; and (2) you shall have fulfilled all your obligations under this Agreement at the applicable closing date. (xiii) You agree and covenant that you will not distribute a Private Placement Memorandum Kit to any offeree with whom you do not have a pre-existing substantive relationship as defined from time to time by the Commission, and you shall require each Selling Agent to agree to the same. As of the date of this Agreement, the term "pre-existing substantive relationship" with a potential offeree means the following: (1) your relationship with the offeree was established before the beginning of the offering of Units in the Partnership, which is July 15, 2005; and (2) you have sufficient information concerning the offeree to determine the offeree's current sophistication and financial circumstances, including that the offeree has such knowledge and experience in financial and business matters that the offeree is capable of evaluating the merits and risks of an investment in the Partnership. 9 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 states requested by you pursuant to Section 6(e)(i) 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 states. 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 those 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. 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 Partnership 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 Partnership is not successfully completed. 10 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 the 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 the following documents: (i) the file memoranda required under Sections 6(e)(iii) and (iv) of this Agreement; and (ii) fully executed subscription documents for each prospective purchaser as required by Section 6(e)(x) of this Agreement. 11. INDEMNIFICATION. (a) You and the Selling Agents shall indemnify and hold harmless the Managing General Partner, the 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. (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. 11 (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; (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. If you elect to terminate this Agreement other than the indemnification provisions of Section 11 of this Agreement, then the Managing General Partner shall be promptly notified by you by telephone, e-mail, facsimile, or telegram, confirmed by letter. 12 (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 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 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. FORMAT OF CHECKS/ESCROW AGENT. Pending receipt of the minimum subscription proceeds of $2,000,000 of the Partnership as set forth in Section 4(e) 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 transfers payable solely to the Escrow Agent as agent for the Partnership as follows: "Atlas Series 26-2005 L.P., Escrow Agent, National City Bank of PA." You agree and shall require the Selling Agents 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. If you receive a check not conforming to the foregoing instructions, then you shall return the check to the Selling Agent not later than noon 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 noon 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 the Partnership and agree that you are bound by the terms of the Escrow Agreement executed by you, the Partnership, and the Managing General Partner, a copy of which is attached to this Agreement as Exhibit "A." 16. TRANSMITTAL PROCEDURES. You and each Selling Agent 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. (a) Pending receipt of the Partnership's minimum subscription proceeds of $2,000,000 as set forth in Section 4(e) of this Agreement, the Selling Agents on receipt of any check from a subscriber shall promptly transmit the check and the original executed subscription documents to you, as Dealer-Manager, by noon of the next business day following receipt of the check by the Selling Agent. By noon 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 documents and a copy of the check to the Managing General Partner. 13 (b) On receipt by you, as Dealer-Manager, of notice from the Managing General Partner that the Partnership's minimum subscription proceeds of $2,000,000 as set forth in Section 4(e) 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, drafts, or money orders payable solely to the Partnership. Thereafter, the Selling Agents shall promptly transmit any and all checks received from subscribers and the original executed subscription documents to you as Dealer-Manager by noon of the next business day following receipt of the check by the Selling Agent. By noon of the next business day following your receipt of the check and the original executed subscription documents, you as Dealer-Manager shall transmit the check and the original executed subscription documents 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 Partnership, 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, the Partnership, or any general partner of the Partnership, nor render the Managing General Partner, the Partnership, or any general partner of the 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. 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: 14 (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 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 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 October 5, 2005 By: /s/ Jack L. Hollander - --------------- ------------------------------------------ Date Jack L. Hollander, Senior Vice President - Direct Participation Programs 15 ATLAS AMERICA SERIES 26-2005 L.P. By: Atlas Resources, Inc., Managing General Partner October 5, 2005 By: /s/ Jack L. Hollander - --------------- ------------------------------------------ Date Jack L. Hollander, Senior Vice President - Direct Participation Programs DEALER-MANAGER ANTHEM SECURITIES, INC., a Pennsylvania corporation October 5, 2005 By: /s/ Justin Atkinson - --------------- ------------------------------------------ Date Justin Atkinson, President 16 EXHIBIT "A" ATLAS AMERICA SERIES 26-2005 L.P. ESCROW AGREEMENT THIS AGREEMENT is made to be effective as of July 15, 2005, by and among Atlas Resources, Inc., a Pennsylvania corporation (the "Managing General Partner"), Anthem Securities, Inc., a Pennsylvania corporation ("Anthem"), Atlas America Series 26-2005 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 for sale to qualified investors (the "Investors") up to 1,400 limited partnership interests in the Partnership (the "Units"). WHEREAS, each Investor will be required to pay his subscription in full on subscribing by check or wire transfer (the "Subscription Proceeds"). WHEREAS, the cost per Unit will be $25,000 subject to certain discounts of up to 11.5% ($2,875 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 ($12,500) subscriptions, with larger subscriptions permitted in $1,000 increments. WHEREAS, the Managing General Partner and Anthem have executed an agreement (" Dealer-Manager Agreement") under which Anthem will solicit subscriptions for Units in all states 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 (the "Dealer-Manager") 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 Dealer-Manager Agreement provides 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; o a 1.5% nonaccountable marketing expense fee; and o a .5% nonaccountable due diligence fee; 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, including any optional subscription by the Managing General Partner, its officers, directors, and Affiliates. 1 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 $35,000,000; or o September 30, 2005, which may not be extended. 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 transfer made payable to "Atlas Series 26-2005 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 of deposit 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. 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" (as defined below); 2 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 Distributable Subscription Proceeds while held by the Escrow Agent in the escrow account. For purposes of this Agreement, "Distributable Subscription Proceeds" are Subscription Proceeds which have been deposited in the escrow account: (1) by wire transfer; or (2) by check, but in the case of checks only at the time that the Escrow Agent believes an amount of time has passed which would usually be sufficient for Subscription Proceeds paid by check to have been returned unpaid by the bank on which the check was drawn and after a 10 day period from the date of deposit. 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 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 remaining 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 which are to be refunded to an Investor or which 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 receives the 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 the 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. (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, 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. 3 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. 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. 4 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 c/o Allegiant Institutional Services 200 Public Square, 5th Floor Cleveland, Ohio 44114 Attention: Dawn DeWerth LOC 01-86PS-01 Phone: (216) 222-9225 Facsimile: (216) 222-7044 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 Atkinson Phone: (412) 262-1680 Facsimile: (412) 262-7430 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. 14. The parties hereto and subscribers acknowledge Escrow Agent has not reviewed and is not making any recommendations with respect to the securities offered. 6 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: /s/ James Schultz --------------------------------------------- James Schultz, Vice President ATLAS RESOURCES, INC. A Pennsylvania corporation By: /s/ Karen A. Black --------------------------------------------- Karen A. Black, Vice President - Partnership Administration ANTHEM SECURITIES, INC. A Pennsylvania corporation By: /s/ Justin T. Atkinson --------------------------------------------- Justin T. Atkinson, President ATLAS AMERICA SERIES 26-2005 L.P. By: ATLAS RESOURCES, INC. Managing General Partner By: /s/ Karen A. Black --------------------------------------------- Karen A. Black - Vice President - Partnership Administration 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. 8 EXHIBIT "B" SELLING AGENT AGREEMENT WITH ANTHEM SECURITIES, INC. TO: _____________________________________________ RE: ATLAS AMERICA SERIES 26-2005 L.P. --------------------------------- Gentlemen: Atlas Resources, Inc. is the Managing General Partner of Atlas America Series 26-2005 L.P., a limited partnership organized under the Delaware Revised Uniform Limited Partnership Act, which is referred to as the "Partnership." The limited partnership interests being offered in the Partnership, which are referred to as the "Units," and the offering are described in the enclosed Private Placement Memorandum dated July 15, 2005, which is referred to as the "Private Placement Memorandum." The Managing General Partner has packaged each numbered Private Placement Memorandum, together with a copy of each item of the sales materials that it has approved for use with potential investors in the Partnership, which are collectively referred to as the "Sales Literature," in kits which are referred to as the "Private Placement Memorandum Kits." Numbered Private Placement Memoranda relating to the Units have been furnished to you in the Private Placement Memorandum Kits, along 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 of the Units in all states, a copy of which has been furnished to you and is incorporated in this Agreement by reference, with the Managing General Partner and the Partnership 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 the Partnership in all states on a "best efforts" basis so as to qualify for the exemption contained in Regulation D promulgated under the Securities Act of 1933, as amended, which is referred to as the "Act," and the provisions of the Private Placement Memorandum. 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 the Partnership pursuant to the provisions of this Agreement in all states in which you are duly registered or licensed as a broker/dealer. 1. REPRESENTATIONS AND WARRANTIES OF SELLING AGENT. You represent and warrant to the Dealer-Manager 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 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. 1 (c) The consummation of the transactions contemplated by this Agreement and the Private Placement Memorandum will not result in the following: (i) any breach of any of the terms or conditions of, or constitute a default under your Articles of Incorporation or Bylaws, or any other indenture, agreement, or other instrument to which you are a party; or (ii) any violation of any order applicable to you of any court or any federal or state regulatory body or administrative agency having jurisdiction over you or over your affiliates. (d) You are not subject to any disqualification described in Rule 505(b)(2)(iii) of Regulation 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 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 Private Placement Memorandum. 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 Regulation D, insofar as Regulation D 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 Regulation D, 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, and 2750, and specifically you agree as set forth below. (i) You shall not offer or sell the Units in any state 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: (1) has been qualified in the state; (2) is exempt from the qualification requirements imposed by the state; or (3) the qualification is otherwise not required. (ii) Units shall not be offered and/or sold by you by means of any form of general solicitation or general advertising, including, but not limited to, the following: (1) any advertisement, article, notice, or other communication published in any newspaper, magazine, or similar media or broadcast over television or radio; (2) any seminar or meeting whose attendees have been invited by any general solicitation or general advertising; or 2 (3) any letter, circular, notice, or other written communication constituting a form of general solicitation or general advertising. (iii) You have received copies of the Private Placement Memorandum Kit relating to the Units and in offering and selling the Units you will rely only on the statements contained in the Private Placement Memorandum and not on any other statements whatsoever, either written or oral, with respect to the details of the offering of Units. You shall provide each offeree with the following: (1) a complete Private Placement Memorandum Kit, which includes a numbered copy of the Private Placement Memorandum, all exhibits incorporated in the Private Placement Memorandum and, without exception, all of the Sales Literature described below; and (2) any numbered supplement or amendment to the Private Placement Memorandum as set forth in (iv) below. Also, each Private Placement Memorandum Kit includes a copy of the following Sales Literature: (1) a flyer entitled "Atlas America Series 26-2005 L.P."; (2) an article entitled "Tax Rewards with Oil and Gas Partnerships"; (3) a brochure of tax scenarios entitled "How an Investment in Atlas America Series 26-2005 L.P. can Help Achieve an Investor's Tax Objectives"; (4) a brochure entitled "Investing in Atlas America Series 26-2005 L.P."; (5) a booklet entitled "Outline of Tax Consequences of Oil and Gas Drilling Programs"; (6) a brochure entitled "The Appalachian Basin: A Prime Drilling Location Which Commands a Premium"; (7) a brochure entitled "Investment Insights - Tax Time"; (8) a brochure entitled "Frequently Asked Questions"; (9) a brochure entitled "AMT - A Little History and Reducing AMT through Natural Gas Partnerships"; (10) a brochure entitled "The Drilling Process"; and (11) possibly other supplementary materials. You agree that, without exception, you will not remove any of the Sales Literature described above from any Private Placement Memorandum Kit before its delivery to an offeree. 3 Further, you shall keep file memoranda, indicating by the number of the Private Placement Memorandum enclosed in the Private Placement Memorandum Kit, to whom each Private Placement Memorandum Kit, which must contain, without exception, all of the Sales Literature, was delivered. (iv) When any supplement or amendment to the Private Placement Memorandum is prepared and delivered to you by the Managing General Partner or the Dealer-Manager, you agree as follows: (1) to distribute each supplement or amendment to the Private Placement Memorandum, identified by number, to every person who has previously received a Private Placement Memorandum Kit from you; (2) to include each supplement or amendment in all future deliveries of any Private Placement Memorandum Kit; and (3) to keep file memoranda indicating to whom each supplement or amendment was delivered. (v) In connection with any offer or sale of the Units, you agree to the following: (1) to comply in all respects with statements set forth in the Private Placement Memorandum, the Partnership Agreement, and any supplements or amendments to the Private Placement Memorandum; (2) not to make any statement inconsistent with the statements in the Private Placement Memorandum, the Partnership Agreement, and any supplements or amendments to the Private Placement Memorandum; (3) not to make any untrue or misleading statements of a material fact in connection with the Units; and (4) not to provide any written information, statements, or sales materials other than the Private Placement Memorandum, the Sales Literature, and any supplements or amendments to the Private Placement Memorandum unless approved in writing by the Managing General Partner. (vi) You shall advise each offeree of Units in the Partnership at the time of the initial offering to him that the Partnership and the Managing General Partner shall during the course of the offering and a reasonable time before sale accord him the opportunity to ask questions and receive answers concerning the terms and conditions of the offering and to obtain any additional information, to the extent possessed by the Partnership or the Managing General Partner or obtainable by either of them without unreasonable effort or expense, that is necessary to verify the accuracy of the information contained in the Private Placement Memorandum. (vii) Before the sale of any of the Units, you shall make reasonable inquiry to determine if the offeree is acquiring the Units for his own account or on behalf of other persons, and that the offeree understands the limitations on the offeree's disposition of the Units set forth in Rule 502(d) of Regulation D. This includes a determination by you that the offeree understands that he must bear the economic risk of the investment for an indefinite period of time because the Units have not been registered under the Act and, thus, cannot be sold unless the Units are subsequently registered under the Act or an exemption from registration under the Act is available. 4 (viii) Before the sale of any of the Units you shall have reasonable grounds to believe that each subscriber is an "accredited investor" as that term is defined in Rule 501(a) of Regulation D. (ix) Units shall not be sold by you to anyone whom you reasonably believe is not an accredited investor. (x) You agree to use your best efforts in the solicitation and sale of the Units, including that: (1) you comply with all the provisions of Regulation D, 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; (2) the prospective purchasers meet the suitability requirements set forth in the Private Placement Memorandum, the Subscription Agreement, this Agreement and the NASD Conduct Rules; and (3) the prospective purchasers properly complete the following forms, which will be included in the Partnership's subscription packet as exhibits to the Private Placement Memorandum: (A) the Subscription Agreement and Annex A attached to the Subscription Agreement [Exhibit (I-B)]; and (B) the Execution Page and Purchaser Questionnaire [Exhibit (C)]; together with any additional forms provided in any supplement or amendment to the Private Placement Memorandum, or otherwise provided to you by the Managing General Partner or the Dealer-Manager 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 packets shall be transmitted as set forth in Section 11 of this Agreement. (f) 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 5 (ii) you shall and have fulfilled all your obligations under this Agreement at the applicable closing date. (g) You agree and covenant that you will not distribute a Private Placement Memorandum Kit to any offeree with whom you do not have a pre-existing substantive relationship as defined from time to time by the Commission. As of the date of this Agreement, you agree that the term "pre-existing substantive relationship" with a potential offeree means the following: (i) your relationship with the offereee was established before the beginning of the offering of Units in the Partnership, which is July 15, 2005; and (ii) you have sufficient information concerning the offeree to determine the offeree's current sophistication and financial circumstances, including that the offeree (or the offeree and its purchaser representative) has such knowledge and experience in financial and business matters that the offeree is capable of evaluating the merits and risks of an investment in the Partnership. 2. COMMISSIONS AND FEES. (a) Subject to the receipt of the minimum required subscription proceeds of $2,000,000 as described in Section 4(e) 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, a 1.5% nonaccountable marketing expense fee, and a .5% nonaccountable due diligence fee per Unit, based on the aggregate amount of all Unit subscriptions to the Partnership secured by the Dealer-Manager or the selling group formed by the Dealer-Manager and accepted by the Managing General Partner. Subject to the performance by you of your obligations under Appendix I to this Agreement, which is incorporated in this Agreement by reference, and subject to the terms and conditions set forth in this Agreement, including the Dealer-Manager's receipt from you of the file memoranda and other 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; (ii) a .5% nonaccountable due diligence fee per Unit, which shall be reduced by the due diligence fees and expenses of any third-party, including, but not limited to, consultants engaged by you that are paid directly to the third-party or are reimbursed to you by the Managing General Partner or the Dealer-Manager; and (iii) a 1.5% nonaccountable marketing expense fee, which shall be reduced for the payment or the reimbursement by the Managing General Partner or the Dealer-Manager to you for costs associated with your national sales conferences, costs associated with regional and/or local meetings that are coordinated by your home office and/or marketing department for registered representatives, and other costs associated with being a sponsor. 6 (b) Your compensation which is owed to you as set forth above, other than the .5% nonaccountable due diligence fee and the 1.5% nonaccountable marketing expense fee, 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(f) of the Dealer-Manager Agreement for breaking escrow for the first closing are satisfied, and approximately every two weeks thereafter until the Partnership's Offering Termination Date, which is described in Section 1 of the Dealer-Manager Agreement. The balance shall be paid to the Dealer-Manager within fourteen business days after the Partnership's Offering Termination Date. The amount of the nonaccountable due diligence fee and the nonaccountable marketing expense fee which is owed to you as set forth above, shall be paid to you within twenty-one business days after the Partnership's Offering Termination Date. (c) As an additional incentive, to the extent permitted by applicable law and subject to the receipt of the minimum subscription proceeds as described in Section 4(e) of the Dealer-Manager Agreement, if you have one or more registered representatives and/or principals who sell at least six Units each in the Partnership, including Units with discounted prices, you shall share in payments from the Managing General Partner equal to 1% of the Partnership's production revenues less the related operating costs, administrative costs, direct costs, and other costs not specifically allocated. Your participation in these payments shall be in the ratio which the total amount of Units sold by all of your registered representatives and/or principals who sell at least six Units each in the Partnership bears to the total number of Units sold by all registered representatives and/or principals (including registered representatives and principals of the Dealer-Manager) who sell at least six Units each in the Partnership. These payments shall be made quarterly. (d) 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 in (a) and (b) above, and your incentive payments as set forth in (c) 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 under this Agreement shall be limited solely to the proceeds of the related amounts owed to it under the Dealer-Manager Agreement. (e) As provided in Section 4(e) of the Dealer-Manager Agreement, the Partnership shall not begin operations unless it receives subscription proceeds for at least $2,000,000 by its Offering Termination Date. If this amount is not secured by the Partnership's Offering Termination Date, then nothing shall be payable to you for the Partnership and all funds advanced by subscribers for Units in the Partnership shall be returned to them with interest earned, if any. 7 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 Partnership, 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. (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 the Partnership 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 the Partnership 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 the following documents: (i) the file memoranda required pursuant to Section 1(e)(iii) and (iv) of this Agreement; and (ii) fully executed subscription documents for each prospective purchaser as required by Section 1(e)(x) of this Agreement. 8 7. INDEMNIFICATION. (a) You shall indemnify and hold harmless the Dealer-Manager, the Managing General Partner, the 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. (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 9 (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. If you elect to terminate this Agreement other than the indemnification provisions of Section 7 of this Agreement, then the Dealer-Manager shall be promptly notified by you by telephone, e-mail, facsimile, or telegram, confirmed by letter. (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(e) 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 wire transfers payable solely to the Escrow Agent as agent for the Partnership as follows: "Atlas Series 26-2005 L.P., Escrow Agent, National City Bank of PA." Also, 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. If you receive a check not conforming to the foregoing instructions, then you shall return the check directly to the subscriber not later than noon 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 noon 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 noon 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 the Partnership's minimum subscription proceeds of $2,000,000 as set forth in Section 4(e) of the Dealer-Manager Agreement, you shall promptly transmit, any and all checks received by you from subscribers and the original executed subscription documents to the Dealer-Manager by noon of the next business day following receipt of the check by you. By noon 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 documents and a copy of the check to the Managing General Partner. 10 (b) On receipt by you of notice from the Managing General Partner or the Dealer-Manager that the Partnership's minimum subscription proceeds of $2,000,000 as set forth in Section 4(e) 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 payable solely to the Partnership. Thereafter, you shall promptly transmit any and all checks received by you from subscribers and the original executed subscription documents to the Dealer-Manager by noon of the next business day following receipt of the check by you. By noon of the next business day following its receipt of the check and original subscription documents, the Dealer-Manager shall transmit the check and the original executed subscription documents to the Managing General Partner. 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. This Agreement shall not constitute you a partner of the Managing General Partner, the Dealer-Manager, the Partnership, any general partner of the Partnership, or any other Selling Agent, nor render the Managing General Partner, the Dealer-Manager, the Partnership, any general partner of the 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. 11 (c) 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: (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. 12 Sincerely, _____________________, 2005 ANTHEM SECURITIES, INC. Date ATTEST: ___________________________ By:_____________________________ (SEAL) Secretary Justin Atkinson, President 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 Private Placement Memorandum Kits which include numbered Private Placement Memoranda and the Sales Literature, and a copy of the Dealer-Manager Agreement referred to above. _____________________, 2005 ____________________________________________, Date a(n) _________________________ corporation, ATTEST: ___________________________ By:__________________________________________ (SEAL) Secretary _____________________________, President _____________________________________________ (Address) _____________________________________________ _____________________________________________ _____________________________________________ (Telephone Number) Our CRD Number is ___________________________ Our Tax ID Number is ________________________ 13 APPENDIX I TO SELLING AGENT AGREEMENT In consideration for the payment to you, as Selling Agent, by the Dealer-Manager of a 7% sales commission, a 1.5% nonaccountable marketing expense fee subject to the reductions set forth in Section 2(a)(iii) of the Selling Agent Agreement, and a .5% nonaccountable due diligence fee subject to the reductions set forth in Section 2(a)(ii) 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. 14 -----END PRIVACY-ENHANCED MESSAGE-----