EX-8 3 ex8.txt EX8.TXT Exhibit 8 OPINION OF KUNZMAN & BOLLINGER, INC. AS TO TAX MATTERS KUNZMAN & BOLLINGER, INC. ATTORNEYS-AT-LAW 5100 N. BROOKLINE, SUITE 600 OKLAHOMA CITY, OKLAHOMA 73112 Telephone (405) 942-3501 Fax (405) 942-3527 Exhibit 8 December 27, 2004 Atlas Resources, Inc. 311 Rouser Road Moon Township, Pennsylvania 15108 RE: Atlas America Public #14-2004 Program - 2005 Tax Opinion Letter Gentlemen: Disclosures and Limitations on Investors' Use of Our Tax Opinion Letter. o Atlas Resources, Inc., as Managing General Partner of each Partnership, has retained us, Kunzman & Bollinger, Inc., as special counsel to assist in the organization and documentation of its public offering of Units in the Partnerships and to provide this tax opinion letter to support the marketing of Units in the Partnerships to potential Participants. Our compensation arrangement with the Managing General Partner is not contingent on all or any part of the intended tax consequences of an investment in a Partnership ultimately being sustained if challenged by the IRS or on the Participants' realization of any tax benefits from the Partnership in which they invest. Also, we have no compensation arrangement with any Person other than the Managing General Partner in connection with the offering of the Units, and we have no referral or fee-sharing arrangement with anyone in connection with the offering of the Units. o Because we have entered into a compensation arrangement with the Managing General Partner to provide certain legal services to the Partnerships as discussed above, this tax opinion letter was not written, and cannot be used by the Participants, for the purpose of avoiding any penalties relating to any reportable transaction understatement of income tax under ss.6662A of the Internal Revenue Code (the "Code") that may be imposed on them. o With respect to any federal tax issue on which we have issued a "more likely than not" or more favorable opinion in this tax opinion letter, our opinion may not be sufficient for the Participants to use for the purpose of avoiding any penalties under the Code that may be imposed on them. o We have not issued a "more likely than not" or more favorable opinion with respect to one or more federal tax issues discussed below in this tax opinion letter. Thus, with respect to those federal tax issues, this tax opinion letter was not written, and cannot be used by the Participants, for purposes of avoiding any penalties under the Code that may be imposed on them. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 2 o This tax opinion letter is not confidential. There are no limitations on the disclosure by the Partnerships or any potential Participant to any other Person of the tax treatment or tax structure of the Partnerships or the contents of this tax opinion letter. o Participants have no contractual protection against the possibility that a portion or all of their intended tax benefits from an investment in a Partnership ultimately are not sustained if challenged by the IRS. (See "Risk Factors - Tax Risks - Your Tax Benefits Are Not Contractually Protected," in the Prospectus and "- Federal Interest and Tax Penalties," below.) o Potential Participants should seek advice based on their particular circumstances from an independent tax advisor with respect to the federal tax issues of an investment in a Partnership. The limitations set forth above on the Participants' use of this tax opinion letter apply only for federal tax purposes. They do not apply to the Participants' right to rely on this tax opinion letter and the discussion in the "Federal Income Tax Considerations" section of the Prospectus under the federal securities laws. Introduction. Atlas America Public #14-2004 Program (the "Program"), is a series of up to three natural gas and oil drilling limited partnerships, all of which have been formed under the Delaware Revised Uniform Limited Partnership Act. The limited partnerships are Atlas America Public #14-2004 L.P., Atlas America Public #14-2005(A) L.P., and Atlas America Public #14-2005(B) L.P. Atlas America Public #14-2004 L.P. had its final closing on November 15, 2004. Atlas Resources, Inc. is the Managing General Partner of all of the limited partnerships. Since the offering of Units in Atlas America Public #14-2004 L.P. has closed, the Managing General Partner has requested our opinions on the material or significant federal income tax issues pertaining to the purchase, ownership and disposition of Units in Atlas America Public #14-2005(A) L.P. and Atlas America Public #14-2005(B) L.P. (each a "Partnership" or both collectively the "Partnerships") by potential Participants. Capitalized terms used and not otherwise defined in this tax opinion letter have the respective meanings assigned to them in the form of Amended and Restated Certificate and Agreement of Limited Partnership for the Partnerships (the "Partnership Agreement"), which is included as Exhibit (A) to the Prospectus. Our Opinions Are Based In Part on Certain Documents We Have Reviewed and Existing Tax Laws. Our opinions and the "Summary Discussion of the Material Federal Income Tax Consequences and Any Significant Federal Tax Issues of an Investment in a Partnership" section of this tax opinion letter are based in part on our review of: o the current Registration Statement on Form S-1 for the Partnerships, as amended, filed with the SEC, including the Prospectus, the Partnership Agreement and the form of Drilling and Operating Agreement included as exhibits in the Prospectus; o other records, certificates, agreements, instruments and documents as we deemed relevant and necessary to review as a basis for our opinions; and KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 3 o current provisions of the Code, existing, temporary and proposed Treasury Regulations, the legislative history of the Code, existing IRS administrative rulings and practices, and judicial decisions. Future changes in existing law, which may take effect retroactively, may cause the actual tax consequences of an investment in the Partnerships to vary substantially from those set forth in this letter, and could render our opinions inapplicable. Our Opinions Are Based In Part On Certain Assumptions. For purposes of our opinions, we have made the assumptions set forth below. o Any funds borrowed by a Participant and used to purchase Units in a Partnership are not borrowed from a Person who has an interest in the Partnership, other than as a creditor, or a "related person", as that term is defined in ss.465 of the Code, to a Person, other than the Participant, having an interest in the Partnership, other than as a creditor, and the Participant is severally, primarily, and personally liable for the borrowed amount. o No Participant has protected himself through nonrecourse financing, guarantees, stop loss agreements or other similar arrangements from loss for amounts paid to a Partnership for his Units. o Under each Partnership's Drilling and Operating Agreement: o the estimated Intangible Drilling Costs are required to be prepaid for specified wells to be drilled and, if warranted, completed; o the drilling of all of the specified wells and substitute wells, if any, is required to be, and actually is, begun on or before the close of the 90th day after the close of the Partnership's taxable year in which the prepayments are made, and the wells are continuously drilled until completed, if warranted, or abandoned; and o the required prepayments are not refundable to the Partnership and any excess prepayments for Intangible Drilling Costs are applied to Intangible Drilling Costs of the other specified wells or substitute wells. o The effect of the allocations of income, gain, loss, deduction, and credit, or items thereof, set forth in the Partnership Agreement, including the allocations of basis and amount realized with respect to natural gas and oil properties, is substantial in light of a Participant's tax attributes that are unrelated to the Partnership in which he invests. We Have Relied On Certain Representations of the Managing General Partner for Purposes of Our Opinions. Many of the federal tax consequences of an investment in a Partnership depend in part on determinations which are inherently factual in nature. Thus, in rendering our opinions we have inquired as to all relevant facts and have obtained from the Managing General Partner specific representations relating to the Partnerships and their proposed activities, some of which are repeated in this letter, in addition to statements made by the Partnerships and the Managing General Partner in the Prospectus concerning the Partnerships and their proposed activities, including forward-looking statements. (See "Forward-Looking Statements and Associated Risks" in the Prospectus.) We have found the Managing General Partner's representations and the statements in the Prospectus to be reasonable and therefore have relied on those representations and statements for purposes of our opinions. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 4 Based on the foregoing, we are satisfied that our opinions take into account all relevant facts, and that the material facts (including our factual assumptions as described above in "- Our Opinions Are Based In Part On Certain Assumptions," and the Managing General Partner's representations, including those set forth below) are accurately and completely described in this tax opinion letter and, where appropriate, in the Prospectus. Any material inaccuracy in the Managing General Partner's representations or the Prospectus may render our opinions inapplicable. Included among the Managing General Partner's representations are the following: o The Partnership Agreement will be duly executed by the Managing General Partner and the Participants in each Partnership and recorded in all places required under the Delaware Revised Uniform Limited Partnership Act and any other applicable limited partnership act. Also, each Partnership will operate its business as described in the Prospectus and in accordance with the terms of the Partnership Agreement, the Delaware Revised Uniform Limited Partnership Act, and any other applicable limited partnership act. o Neither Partnership will elect to be taxed as a corporation. o Each Partnership will own only Working Interests in all of its Prospects. o Neither Partnership's Units will be traded on an established securities market. o A typical Participant in each Partnership will be a natural person who purchases Units in this offering and is a U.S. citizen. o The Investor General Partner Units in a Partnership will not be converted by the Managing General Partner to Limited Partner Units until after all of the wells in that Partnership have been drilled and completed. The Managing General Partner anticipates that all of the productive wells in each Partnership will be drilled, completed and placed in service no more than 12 months after that Partnership's final closing. Thus, the Managing General Partner anticipates that conversion will be in 2006 for both Atlas America Public #14-2005(A) L.P. and Atlas America Public #14-2005(B) L.P. o Each Partnership ultimately will own legal title to its Working Interest in all of its Prospects, although initially title to the Prospects will be held in the name of the Managing General Partner, its Affiliates or other third-parties as nominee for the Partnership, in order to facilitate the acquisition of the Leases. o Generally, 100% of the Working Interest in each Partnership's Prospects will be assigned to that Partnership, however, the Managing General Partner anticipates that each Partnership will acquire less than 100% of the Working Interest in one or more of its Prospects, and although prepayments of Intangible Drilling Costs and the Participants' share of the Tangible Costs will be required of each Partnership under its Drilling and Operating Agreement with the Managing General Partner, acting as general drilling contractor, the other owners of Working Interests in those wells will not be required to prepay any of their share of the costs of drilling the wells. o The Drilling and Operating Agreement for each Partnership will be duly executed and will govern the drilling and, if warranted, the completion and operation of that Partnership's wells. o Each Partnership will make the election under ss.263(c) of the Code and Treas. Reg. ss.1.612-4(a) to expense, rather than capitalize, the Intangible Drilling Costs of all of its wells. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 5 o Based on information the Managing General Partner has concerning drilling rates of third-party drilling companies in the Appalachian Basin, the estimated costs of non-affiliated persons to drill and equip wells in the Appalachian Basin as reported for 2002 by an independent industry association which surveyed other non-affiliated operators in the area, and information it has concerning increases in drilling costs in the area since then, the amounts that will be paid by the Partnerships to the Managing General Partner or its Affiliates under the Drilling and Operating Agreement to drill and complete each Partnership's wells at Cost plus 15% are reasonable and competitive amounts that ordinarily would be paid for similar services in similar transactions between Persons having no affiliation and dealing with each other "at arms' length" in the proposed areas of operations. o For its services as general drilling contractor, the Managing General Partner anticipates that on average over all of the wells drilled and completed by each Partnership, assuming a 100% Working Interest in each well, it will have reimbursement of general and administrative overhead of approximately $12,690 per well and a profit of 15% (approximately $23,976) per well, with respect to the Intangible Drilling Costs and the portion of Tangible Costs paid by the Participants in each Partnership as described in "Compensation - Drilling Contracts" in the Prospectus. o Based on the Managing General Partner's experience and its knowledge of industry practices in the Appalachian Basin, its allocation of the drilling and completion price to be paid by each Partnership to the Managing General Partner or its Affiliates as a third-party general drilling contractor to drill and complete a well between Intangible Drilling Costs and Tangible Costs as set forth in "Compensation - Drilling Contracts" in the Prospectus is reasonable. o The Managing General Partner anticipates that all of the subscription proceeds of each Partnership will be expended in 2005, and the related income, if any, and deductions, including the deduction for Intangible Drilling Costs, will be reflected on its Participants' federal income tax returns for that period. o The Managing General Partner does not anticipate that any of the Partnerships' production of natural gas and oil from their respective wells in 2005, if any, will qualify for the marginal well production credit in 2005, because the prices for natural gas and oil in 2004 were substantially above the $2.00 per mcf and $18.00 per barrel prices where the credit phases out completely. o The Managing General Partner anticipates that Atlas America Public #14-2005(A) L.P., which has a targeted closing date of March 31, 2005 (which is not binding on the Partnership), will drill and complete all of its wells in 2005 and, therefore, will not prepay in 2005 any of its Intangible Drilling Costs for drilling activities that will begin in 2006. However, depending primarily on when it receives its subscription proceeds, Atlas America Public #14-2005(A) L.P. may have its final closing as late in the year as December 31, 2005. Therefore, depending primarily on when its subscription proceeds are received, the Managing General Partner further anticipates that Atlas America Public #14-2005(A) L.P. may prepay in 2005 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2006. Atlas America Public #14-2005(B) L.P., which will not begin offering any remaining unsold Units in the Program until after the final closing of Atlas America Public #14-2005(A) L.P., also may have its final closing as late as December 31, 2005, and, therefore, may prepay in 2005 most, if not all, of its Intangible Drilling Costs for drilling activities that will begin in 2006. o Each Partnership will attempt to comply with the guidelines set forth in Keller v. Commissioner with respect to any prepaid Intangible Drilling Costs. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 6 o Each Partnership will have a calendar year taxable year, and will use the accrual method of accounting for federal income tax purposes. o The Managing General Partner anticipates that most, if not all, of the natural gas and oil production from each Partnership's productive wells will be "marginal production" as that term is defined in ss.613A(c)(6)(E) of the Code, and each Partnership's gross income from the sale of its natural gas and oil production will qualify under the Code for the potentially higher rates of percentage depletion available under the Code for marginal production of natural gas and oil. o To the extent a Partnership has cash available for distribution, it is the Managing General Partner's policy that the Partnership's cash distributions to its Participants will not be less than the Managing General Partner's estimate of the Participants' income tax liability with respect to that Partnership's income. o The Managing General Partner does not anticipate that the amount of its amortization deductions for organization expenses related to the creation of a Partnership will be material in amount as compared to the total subscription proceeds of that Partnership. o The principal purpose of each Partnership is to locate, produce and market natural gas and oil on a profitable basis, apart from tax benefits, as discussed in the Prospectus. (See, in particular, "Prior Activities," "Management," "Proposed Activities," and "Appendix A" in the Prospectus. o Appendix A in the Prospectus will be supplemented or amended to cover a portion of the specific Prospects proposed to be drilled by Atlas America Public #14-2005(B) L.P. when Units in that Partnership are first offered to prospective Participants. o Due to the restrictions on transfers of Units in the Partnership Agreement, the Managing General Partner does not anticipate that either Partnership will ever be considered as terminated under ss.708(b) of the Code (relating to the transfer of 50% or more of a Partnership's capital and profits interests in a 12-month period). o Based in part on its past experience, the Managing General Partner anticipates that there will be more than 100 Partners in each Partnership. The Managing General Partner, however, does not anticipate that either Partnership will elect to be governed under simplified tax reporting and audit rules as an "electing large partnership, because most limitations affecting the calculation of the taxable income and tax credits of an electing large partnership are generally applied at the partnership level and not the partner level. o Due to the complexities and added expense of the tax accounting required to implement a ss.754 election to adjust the basis of a Partnership's property when Units are sold, taking into account the limitations on the sale of the Partnership's Units, neither Partnership will make the ss.754 election. o The Managing General Partner and its Affiliates will not make or arrange financing for potential Participants to use to purchase Units in a Partnership. o The Managing General Partner will notify the Participants of any IRS audits or other tax proceedings involving their Partnership, and will provide the Participants any other information regarding the proceedings as may be required by the Partnership Agreement or law. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 7 o Each Partnership will provide its Participants with the tax information applicable to their investment in the Partnership necessary to prepare their tax returns. o The Partnerships generally will not distribute their assets in-kind to their Participants. o The Managing General Partner anticipates that each Partnership will incur a tax Loss during at least its first taxable year, due primarily to the amount of Intangible Drilling Costs it intends to claim as a deduction, and that the Loss in each Partnership's first taxable year will be in an amount equal or greater than $1.8 million, with the actual amount of the Loss of each Partnership depending primarily on the amount of the Partnership's subscription proceeds. o The Managing General Partner believes that each productive well drilled by a Partnership will produce for more than five years, and that it is likely to be many years after the well was drilled before its commercial natural gas and oil reserves have been produced and depleted. o Based primarily on the Managing General Partner's past experience as shown in "Prior Activities" in the Prospectus, each Partnership's total abandonment losses under ss.165 of the Code, if any, which could include, for example, the abandonment by a Partnership of wells drilled which are nonproductive (i.e. a "dry hole") or wells which have been operated until their commercial natural gas and oil reserves have been depleted (and each Participant's allocable share of those abandonment losses), will be less, in the aggregate, than $2 million in any taxable year and less than an aggregate total of $4 million during the Partnership's first six taxable years. o The Managing General Partner does not anticipate that the Partnerships will have a significant book-tax difference for purposes of the reportable transaction rules in any of their taxable years since under those rules book-tax differences arising from depletion, Intangible Drilling Costs, and depreciation and amortization methods, useful lives, etc. are not taken into account. o No productive well of a Partnership which may generate marginal well production tax credits will be held by the Partnership for 45 days or less. In addition, even if all of both Partnerships' wells were wells were taken into account, which the Managing General Partner anticipates would be approximately 407 gross wells, any marginal well production credits arising from the natural gas and oil production for that short period of time would not exceed $250,000. o The Managing General Partner will attempt to eliminate or reduce any gain to a Partnership from a Farmout, if any. Scope of Our Review. We have considered the provisions of 31 CFR, Part 10, ss.10.35 (Treasury Department Circular No. 230) on tax law opinions. We believe that this tax opinion letter and, where appropriate, the Prospectus fully and fairly address all of the material federal tax issues and any significant federal tax issues associated with an investment in a Partnership by a typical Participant. In this regard, the Managing General Partner has represented that a typical Participant in a Partnership will be a natural person who purchases Units in a Partnership in this offering and is a U.S. citizen. For purposes of this tax opinion letter, a federal tax issue is a question concerning the federal tax treatment of an item of income, gain, loss, deduction, or credit; the existence or absence of a taxable transfer of property; or the value of property for federal tax purposes. A federal tax issue is significant if the IRS has a reasonable basis for a successful challenge and its resolution could have a significant impact, whether beneficial or adverse and under any reasonably foreseeable circumstance, on the overall federal tax treatment of the Partnerships or a Participant's investment in a Partnership. We consider a federal tax issue to be material if its resolution: KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 8 o could shelter from federal income taxes a significant portion of a Participant's income from sources other than the Partnership in which he invests by providing the Participant with: o deductions in excess of the Participant's share of his Partnership's income in any taxable year; or o marginal well production credits in excess of the Participant's tentative regular federal income tax liability on the Participant's share of his Partnership's federal net taxable income in any taxable year; or o could reasonably affect the potential applicability of federal tax penalties against the Participants. Also, in ascertaining that all material federal tax issues and any significant federal tax issues have been considered, evaluating the merits of those issues and evaluating whether the federal tax treatment set forth in our opinions is the proper tax treatment, we have not taken into account the possibility that a tax return will not be audited, that an issue will not be raised on audit, or that an issue will be settled. Opinions. Although our opinions express what we believe a court would probably conclude if presented with the applicable issues, our opinions are only predictions, and are not guarantees, of the outcome of the particular tax issues being addressed. The intended federal tax consequences and federal tax benefits of a Participant's investment in a Partnership are not contractually protected as described in greater detail in "Risk Factors - Tax Risks - Your Tax Benefits Are Not Contractually Protected" in the Prospectus. The IRS could challenge our opinions, and the challenge could be sustained in the courts and cause adverse tax consequences to the Participants. Taxpayers bear the burden of proof to support claimed deductions and credits, and our opinions are not binding on the IRS or the courts. The opinions we give below are based in part on the Managing General Partner's representations and our assumptions relating to the Partnerships which are set forth in preceding sections of this tax opinion letter. Subject to the limitations, notices and exceptions concerning our opinions set forth in this tax opinion letter, and except as noted otherwise below, in our opinion the federal tax treatment with respect to each federal tax issue of an investment in a Partnership by a typical Participant as set forth below is the proper tax treatment of that issue and will be upheld on the merits if challenged by the IRS and litigated. (1) Partnership Classification. Each Partnership will be classified as a partnership for federal income tax purposes, and not as a corporation. The Partnerships, as such, will not pay any federal income taxes, and all items of income, gain, loss, deduction, and credit, if any, of the Partnerships will be reportable by the Partners in the Partnership in which they invest. (2) Passive Activity Classification. o Generally, the passive activity limitations on losses and credits under ss.469 of the Code will apply to the Limited Partners in a Partnership, but will not apply to the Investor General Partners in the Partnership before the conversion of the Investor General Partner Units to Limited Partner Units in the Partnership. o A Partnership's income, gain and credits, if any, from its natural gas and oil properties which are allocated to its Limited Partners, other than net income allocated to converted Investor General Partners and any related credits, generally will be characterized as: o passive activity income which may be offset by passive activity losses; and KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 9 o passive activity credits which a Limited Partner may use to offset a portion or all of the Limited Partner's regular federal income tax liability from passive income received by the Limited Partner from the Partnership or other passive activities, other than publicly traded partnership passive activities. o Income or gain attributable to investments of working capital of a Partnership will be characterized as portfolio income, which cannot be offset by passive activity losses, and will not generate any marginal well production credits. (3) Not a Publicly Traded Partnership. Neither Partnership will be treated as a publicly traded partnership under the Code. (4) Availability of Certain Deductions. Business expenses, including payments for personal services actually rendered in the taxable year in which accrued, which are reasonable, ordinary and necessary and do not include amounts for items such as Lease acquisition costs, Tangible Costs, organization and syndication fees and other items which are required to be capitalized, are currently deductible. (5) Intangible Drilling Costs. Although each Partnership will elect to deduct currently all Intangible Drilling Costs, each Participant may still elect to capitalize and deduct all or part of his share of his Partnership's Intangible Drilling Costs ratably over a 60 month period as discussed in "- Alternative Minimum Tax," below. Subject to the foregoing, Intangible Drilling Costs paid by a Partnership under the terms of bona fide drilling contracts for the Partnership's wells will be deductible in the taxable year in which the payments are made and the drilling services are rendered. This opinion is subject to certain restrictions summarized below, including basis and "at risk" limitations, and the passive activity loss limitation with respect to the Limited Partners. (6) Prepayments of Intangible Drilling Costs. Any prepayments of Intangible Drilling Costs by a Partnership will be deductible in the year in which the prepayments are made. This opinion is subject to certain restrictions summarized below, including basis and "at risk" limitations, and the passive activity loss limitation with respect to the Limited Partners. In addition, this opinion is subject to each Participant's election to capitalize and amortize a portion or all of the Participant's share of his Partnership's deductions for Intangible Drilling Costs as set forth in (5) above. (7) Depletion Allowance. The greater of cost depletion or percentage depletion will be available to qualified Participants as a current deduction against their share of their Partnership's natural gas and oil production income, subject to certain restrictions summarized below. (8) MACRS. Each Partnership's reasonable costs for equipment placed in its respective productive wells which cannot be deducted immediately ("Tangible Costs") will be eligible for cost recovery deductions under the Modified Accelerated Cost Recovery System ("MACRS"), generally over a seven year "cost recovery period" beginning in the taxable year each well is drilled, completed and made capable of production, i.e. placed in service, subject to certain restrictions summarized below, including basis and "at risk" limitations, and the passive activity loss limitation in the case of the Limited Partners. (9) Tax Basis of Units. Each Participant's initial adjusted tax basis in his Units will be the purchase price paid for the Units. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 10 (10) At Risk Limitation on Losses. Each Participant's initial "at risk" amount in the Partnership in which he invests will be the purchase price paid for the Units. (11) Allocations. The allocations of income, gain, loss, deduction, and credit, or items thereof, and distributions set forth in the Partnership Agreement of each Partnership, including the allocations of basis and amount realized with respect to the Partnership's natural gas and oil properties, will govern each Participant's allocable share of those items of each Participant in the Partnership to the extent the allocations do not cause or increase a deficit balance in his Capital Account, and subject to each Participant's obligation to separately keep a record of his share of the adjusted basis of the Partnership's natural gas and oil properties for depletion and other purposes. (12) Subscription. No gain or loss will be recognized by the Participants on payment of their subscriptions to the Partnership in which they invest. (13) Profit Motive, IRS Anti-Abuse Rule and Potentially Relevant Judicial Doctrines. The Partnerships will possess the requisite profit motive under ss.183 of the Code. Also, the IRS anti-abuse rule in Treas. Reg. ss.1.701-2 and potentially relevant judicial doctrines will not have a material adverse effect on the tax consequences of an investment in a Partnership by a typical Participant as described in our opinions. These opinions are based in part on: o the results of the previous partnerships sponsored by the Managing General Partner as set forth in "Prior Activities" in the Prospectus; o the Managing General Partner's representations; and o the geological evaluations and the other information for the Partnerships' proposed drilling areas and the specific Prospects proposed to be drilled by each Partnership which are, or will be, included in "Proposed Activities" and Appendix A in the Prospectus. (14) Reportable Transaction Rules. It is more likely than not that each Partnership will not be a reportable transaction under the Code, and their Participants will not be subject to the reportable transaction understatement of federal income tax penalty under the Code with respect to their investment in a Partnership. (15) Overall Conclusion. Subject to the rest of this tax opinion letter, our overall conclusion is that the federal tax treatment of a typical Participant's investment in a Partnership as set forth above in our opinions is the proper federal tax treatment. The reason we have reached this overall conclusion is that our evaluation of the federal income tax laws and the expected activities of the Partnerships as represented to us by the Managing General Partner in this tax opinion letter and as described in the Prospectus causes us to believe (to summarize our opinions above) that the deduction by each Participant of all, or substantially all, of his allocable share of his Partnership's Intangible Drilling Costs in 2005 (even if the drilling of a portion or all of his Partnership's wells begins after December 31, 2005, but on or before March 31, 2006) is the proper federal tax treatment, subject to the various limitations on a Participant's deductions and each Participant's option to capitalize and amortize a portion or all of the Participant's deduction for Intangible Drilling Costs as discussed in this tax opinion letter. Also, the discussion in the Prospectus under the caption "FEDERAL INCOME TAX CONSIDERATIONS," insofar as it contains statements of federal income tax law, is correct in all material respects. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 11 Summary Discussion of the Material Federal Income Tax Consequences and Any Significant Federal Tax Issues of an Investment in a Partnership In General. Our tax opinions are limited to those set forth above. The following is a summary of all of the material federal income tax consequences and any significant federal tax issues of the purchase, ownership and disposition of a Partnership's Units which will apply to typical Participants in the Partnership. Except as otherwise noted below, however, different tax considerations from those discussed in this tax opinion letter may apply to certain Participants, such as foreign persons, corporations, partnerships, trusts, and other prospective Participants which are subject to special treatment under the Code and are not treated as typical Participants for federal income tax purposes. Also, the proper treatment of the tax attributes of a Partnership by a typical Participant on his individual federal income tax return may vary from that by another typical Participant. This is because the practical utility of the tax aspects of any investment depends largely on each Participant's particular income tax position in the year in which items of income, gain, loss, deduction, or credit, if any, are properly taken into account in computing the Participant's federal income tax liability. In addition, the IRS may challenge the deductions and credits claimed by a Partnership or a Participant, or the taxable year in which the deductions and credits are claimed, and it is possible that the challenge would be upheld if litigated. Accordingly, each prospective Participant is urged to seek qualified, professional advice based on the Participant's particular circumstances from an independent tax advisor in evaluating the potential tax consequences to him of an investment in a Partnership. Partnership Classification. For federal income tax purposes a partnership is not a taxable entity. Thus, the partners, rather than the partnership, report their share of all items of income, gain, loss, deduction, tax credits, and tax preferences from the partnership's operations on their personal federal income tax return. A business entity with two or more members is classified for federal tax purposes as either a corporation or a partnership. Treas. Reg. ss.301.7701-2(a). A corporation includes a business entity organized under a State statute which describes the entity as a corporation, body corporate, body politic, joint-stock company or joint-stock association. Treas. Reg. ss.301.7701-2(b). Each Partnership, however, has been formed as a limited partnership under the Delaware Revised Uniform Limited Partnership Act which describes each Partnership as a "partnership." Thus, each Partnership automatically will be classified as a partnership since the Managing General Partner has represented that neither Partnership will elect to be taxed as a corporation. Limitations on Passive Activities. Under the passive activity rules of ss.469 of the Code, all income of a taxpayer who is subject to the rules is categorized as: o income from passive activities such as limited partners' interests in a business; o active income such as salary, bonuses, etc.; or o portfolio income. "Portfolio income" consists of: o interest, dividends and royalties unless earned in the ordinary course of a trade or business; and o gain or loss not derived in the ordinary course of a trade or business on the sale of property that generates portfolio income or is held for investment. Losses generated by passive activities can offset only passive income and cannot be applied against active income or portfolio income. Similar rules apply with respect to tax credits. (See " - Marginal Well Production Credits," below.) KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 12 The passive activity rules apply to individuals, estates, trusts, closely held C corporations which generally are corporations with five or fewer individuals who own directly or indirectly more than 50% of the stock, and personal service corporations other than corporations where the employee-owners together own less than 10% of the stock. However, a closely held C corporation, other than a personal service corporation, may use passive losses and credits to offset taxable income of the company figured without regard to passive income or loss or portfolio income. Passive activities include any trade or business in which the taxpayer does not materially participate on a regular, continuous, and substantial basis. Under the Partnership Agreement, Limited Partners will not have material participation in the Partnership in which they invest and generally will be subject to the passive activity limitations. Investor General Partners also do not materially participate in the Partnership in which they invest. However, because each Partnership will own only Working Interests, as defined by the Code, in its wells, and Investor General Partners will not have limited liability under the Delaware Revised Uniform Limited Partnership Act until they are converted to Limited Partners, their deductions and any credits generally will not be treated as passive deductions or credits under the Code before the conversion. I.R.C. ss.469(c)(3). (See "- Conversion from Investor General Partner to Limited Partner" and "- Marginal Well Production Credits," below.) However, if an Investor General Partner invests in a Partnership through an entity which limits his liability, for example, a limited partnership in which he is not a general partner, a limited liability company or an S corporation, then generally he will be subject to the passive activity limitations the same as a Limited Partner. Contractual limitations on the liability of Investor General Partners under the Partnership Agreement, however, such as insurance, limited indemnification by the Managing General Partner, etc. will not cause Investor General Partners to be subject to the passive activity loss limitations. A Limited Partner's "at risk" amount is reduced by losses allowed under ss.465 of the Code even if the losses are suspended by the passive activity loss limitation. (See "- `At Risk' Limitation For Losses," below.) Similarly, a Limited Partner's basis is reduced by deductions even if the deductions are suspended under the passive activity loss limitation. (See "- Tax Basis of Units," below.) Suspended losses and credits may be carried forward indefinitely, but not back, and used to offset future years' passive activity income, or offset passive activity regular income tax liability (in the case of passive activity credits). A suspended loss, but not a credit, is allowed in full when the entire interest in a passive activity is sold to an unrelated third-party in a taxable transaction, and in part on the disposition of substantially all of the interest in a passive activity if the suspended loss as well as current gross income and deductions can be allocated to the part disposed of with reasonable certainty. In an installment sale, passive losses and credits become available in the same ratio that gain recognized each year bears to the total gain on the sale. Any suspended losses remaining at a taxpayer's death are allowed as deductions on the decedent's final return, subject to a reduction to the extent the basis of the property in the hands of the transferee exceeds the property's adjusted basis immediately before the decedent's death. If a taxpayer makes a gift of his entire interest in a passive activity, the basis in the property of the person receiving the gift is increased by any suspended losses and no deductions are allowed. If the interest is later sold at a loss, the basis in the property of the person receiving the gift is limited to the fair market value on the date the gift was made. Publicly Traded Partnership Rules. Net losses and most net credits of a partner from a publicly traded partnership are suspended and carried forward to be netted against income or regular federal income tax liability, respectively, from that publicly traded partnership only. In addition, net losses from other passive activities may not be used to offset net passive income from a publicly traded partnership. I.R.C. ss.ss.469(k)(2) and 7704. A publicly traded partnership is a partnership in which interests in the partnership are traded on an established securities market, or in which interests in the partnership are readily tradable on either a secondary market or the substantial equivalent of a secondary market. However, in our opinion neither Partnership will be treated as a publicly traded partnership under the Code. This opinion is based primarily on the substantial restrictions in the Partnership Agreement on each Participant's ability to transfer his Units in the Partnership in which he invests. (See "Transferability of Units - Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement" in the Prospectus.) Also, the Managing General Partner has represented that neither Partnership's Units will be traded on an established securities market. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 13 Conversion from Investor General Partner to Limited Partner. If a Participant invests in a Partnership as an Investor General Partner, then his share of the Partnership's deduction for Intangible Drilling Costs in 2005 will not be subject to the passive activity loss limitation. This is because the Managing General Partner has represented that the Investor General Partner Units in a Partnership will not be converted by the Managing General Partner to Limited Partner Units until after all of the wells in that Partnership have been drilled and completed. In this regard, the Managing General Partner anticipates that all of the productive wells in each Partnership will be drilled, completed and placed in service no more than 12 months after that Partnership's final closing. Thus, the Managing General Partner anticipates that conversion will be in 2006 for both Atlas America Public #14-2005(A) L.P. and Atlas America Public #14-2005(B) L.P. (See "Actions to be Taken by Managing General Partner to Reduce Risks of Additional Payments by Investor General Partners" in the Prospectus, and "- Drilling Contracts," below.) After the Investor General Partner Units have been converted to Limited Partner Units, each former Investor General Partner will have limited liability as a limited partner under the Delaware Revised Uniform Limited Partnership Act with respect to his interest in his Partnership's activities after the date of the conversion. Concurrently, the former Investor General Partner will become subject to the passive activity rules as a limited partner. However, the former Investor General Partner previously will have received a non-passive loss as an Investor General Partner in 2005 as a result of the Partnership's deduction for Intangible Drilling Costs. Therefore, the Code requires that his net income from the Partnership's wells after his conversion to a limited partner must continue to be characterized as non-passive income which cannot be offset with passive losses. I.R.C. ss.469(c)(3)(B). For a discussion of the effect of this rule on an Investor General Partner's tax credits from his Partnership, if any, see " - Marginal Well Production Credits," below. The conversion of the Investor General Partner Units into Limited Partner Units should not have any other adverse tax consequences on an Investor General Partner unless his share of any Partnership liabilities is reduced as a result of the conversion. Rev. Rul. 84-52, 1984-1 C.B. 157. A reduction in a partner's share of liabilities is treated as a constructive distribution of cash to the partner, which reduces the basis of the partner's interest in the partnership and is taxable to the extent it exceeds his basis. (See "- Tax Basis of Units," below.) Taxable Year. Each Partnership will have a calendar year taxable year. I.R.C. ss.ss.706(a) and (b). The taxable year of a Partnership is important to a Participant because the Partnership's deductions, tax credits, if any, income and other items of tax significance must be taken into account on the Participant's personal federal income tax return for his taxable year within or with which the Partnership's taxable year ends. The tax year of a partnership generally must be the tax year of one or more of its partners who have an aggregate interest in partnership profits and capital of greater than 50%. Method of Accounting. Each Partnership will use the accrual method of accounting for federal income tax purposes. I.R.C. ss.448(a). Under the accrual method of accounting, income is taken into account for the year in which all events have occurred which fix the right to receive it and the amount is determinable with reasonable accuracy, rather than the time of receipt. Consequently, Participants in a Partnership may have income tax liability resulting from the Partnership's accrual of income in one tax year that it does not receive until the next tax year. Expenses are deducted for the year in which all events have occurred that determine the fact of the liability, the amount is determinable with reasonable accuracy and the economic performance test is satisfied. Under ss.461(h) of the Code, if the liability of the taxpayer arises out of the providing of services or property to the taxpayer by another person, economic performance occurs as the services or property, respectively, are provided. If the liability of the taxpayer arises out of the use of the property by the taxpayer, economic performance occurs as the property is used. o A special rule in the Code, however, provides that there is economic performance in the current taxable year with respect to amounts paid in that taxable year for Intangible Drilling Costs of drilling and completing a natural gas or oil well so long as the drilling of the well begins before the close of the 90th day after the close of the taxable year in which the payments were made. I.R.C. ss.461(i). (See "- Drilling Contracts," below, for a discussion of the tax treatment of any prepaid Intangible Drilling Costs by Atlas America Public #14-2005(A) L.P. and Atlas America Public #14-2005(B) L.P.) KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 14 2005 Expenditures. The Managing General Partner anticipates that all of the subscription proceeds of each Partnership will be expended in 2005, and the related income and deductions, including the deduction for Intangible Drilling Costs, will be reflected on its Participants' federal income tax returns for that period. (See "Capitalization and Source of Funds and Use of Proceeds" and "Participation in Costs and Revenues" in the Prospectus.) In this regard, the Managing General Partner does not anticipate that any of the Partnerships' production of natural gas and oil from their respective wells in 2005, if any, will qualify for the marginal well production credit in 2005, because the prices for natural gas and oil in 2004 were substantially above the $2.00 per mcf and $18.00 per barrel prices where the credit phases out completely. (See "- Drilling Contracts" and "- Marginal Well Production Credits," below.) Depending primarily on when each Partnership's subscriptions are received, the Managing General Partner anticipates that either or both of Atlas America Public #14-2005(A) L.P. and Atlas America Public #14-2005(B) L.P., which may both have their final closing on any date up to and including December 31, 2005, may prepay in 2005 most, if not all, of its respective Intangible Drilling Costs for drilling activities that will begin in 2006. However, Atlas America Public #14-2005(A) L.P. has a targeted closing date of March 31, 2005 (which is not binding on the Partnership), and depending primarily on when it receives its subscriptions, it may not prepay in 2005 any of its Intangible Drilling Costs for drilling activities that will begin in 2006. The offering of Units in Atlas America Public #14-2005(B) L.P. will not begin until after the final closing of Atlas America Public #14-2005(A) L.P. (See "- Drilling Contracts," below.) Availability of Certain Deductions. Ordinary and necessary business expenses, including reasonable compensation for personal services actually rendered, are deductible in the year incurred. Treasury Regulation ss.1.162-7(b)(3) provides that reasonable compensation is only the amount as would ordinarily be paid for like services by like enterprises under like circumstances. In this regard, the Managing General Partner has represented that the amounts that will be paid by the Partnerships to it or its Affiliates under the Drilling and Operating Agreement to drill and complete each Partnership's wells at Cost plus 15% are reasonable and competitive amounts that ordinarily would be paid for similar services in similar transactions between Persons having no affiliation and dealing with each other "at arms' length" in the proposed areas of both Partnerships' operations. (See "Compensation" in the Prospectus and "- Drilling Contracts," below.) The fees paid to the Managing General Partner and its Affiliates by the Partnerships will not be currently deductible, however, to the extent it is determined by the IRS or the courts that they are: o in excess of reasonable compensation; o properly characterized as organization or syndication fees or other capital costs such as the acquisition cost of the Leases; or o not "ordinary and necessary" business expenses. (See "- Partnership Organization and Offering Costs," below.) In the event of an audit, payments to the Managing General Partner and its Affiliates by a Partnership will be scrutinized by the IRS to a greater extent than payments to an unrelated party. Although the Partnerships will engage in the production of natural gas and oil from wells drilled in the United States, the Partnerships will not qualify for the "U.S. production activities deduction." This is because the deduction cannot exceed 50% of the IRS Form W-2 wages paid by a taxpayer for a tax year, and the Partnerships will not pay any Form W-2 wages since they will not have any employees. Instead, the Partnerships will rely on the Managing General Partner and its Affiliates to manage them and their respective businesses. (See "Management" in the Prospectus.) KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 15 Intangible Drilling Costs. Assuming a proper election and subject to the limitations on deductions and losses summarized elsewhere in this letter, including the basis and "at risk" limitations, and the passive activity loss limitation in the case of Limited Partners, each Participant will be entitled to deduct his share of his Partnership's Intangible Drilling Costs, which include items which do not have salvage value, such as labor, fuel, repairs, supplies and hauling necessary to the drilling of a well. I.R.C. ss.263(c), Treas. Reg. ss.1.612-4(a). If a Partnership re-enters an existing well as described in "Proposed Activities - Primary Areas of Operations - Mississippian/Upper Devonian Sandstone Reservoirs, Fayette County, Pennsylvania" in the Prospectus, the costs of deepening the well and completing it to deeper reservoirs, if any, (other than Tangible Costs) generally will be treated as Intangible Drilling Costs. Drilling and completion costs of a re-entry well which are not related to deepening the well, if any, however, other than Tangible Costs, generally will be treated as operating expenses which should be expensed in the taxable year they are incurred for federal income tax purposes. Those costs (other than Tangible Costs) of the re-entry well, however, will not be characterized as Operating Costs, instead of Intangible Drilling Costs, for purposes of allocating the payment of the costs between the Managing General Partner and the Participants under the Partnership Agreement. (See "Participation in Costs and Revenues" in the Prospectus, and "- Limitations on Passive Activities," above and "- Tax Basis of Units" and "- `At Risk' Limitation For Losses," below.) For a discussion of the federal tax treatment of Tangible Costs, see "- Depreciation - Modified Accelerated Cost Recovery System ("MACRS")," below. These deductions are subject to recapture as ordinary income rather than capital gain on the sale or other taxable disposition of the property or a Participant's Units. (See "- Sale of the Properties" and "- Disposition of Units," below.) Also, productive-well Intangible Drilling Costs may subject a Participant to an alternative minimum tax in excess of regular tax unless the Participant elects to deduct all or part of these costs ratably over a 60 month period. (See "- Alternative Minimum Tax," below.) Under the Partnership Agreement, not less than 90% of the subscription proceeds received by each Partnership from its Participants will be used to pay 100% of the Partnership's Intangible Drilling Costs of drilling and completing its wells. (See "Application of Proceeds" and "Participation in Costs and Revenues" in the Prospectus.) The IRS could challenge the characterization of a portion of these costs as currently deductible Intangible Drilling Costs and recharacterize the costs as some other item which may not be currently deductible. However, this would have no effect on the allocation and payment of the Intangible Drilling Costs by the Participants under the Partnership Agreement. In the case of corporations, other than S corporations, which are "integrated oil companies," the amount allowable as a deduction for Intangible Drilling Costs in any taxable year is reduced by 30%. I.R.C. ss.291(b)(1). Integrated oil companies are: o those taxpayers who directly or through a related person engage in the retail sale of natural gas and oil and whose gross receipts for the taxable year from such activities exceed $5,000,000; or o those taxpayers and related persons who have refinery production in excess of 50,000 barrels on any day during the taxable year. I.R.C. ss.291(b)(4). Amounts disallowed as a current deduction are allowable as a deduction ratably over the 60-month period beginning with the month in which the costs are paid or incurred. The Partnerships will not be integrated oil companies. Each Participant is urged to seek advice based on his particular circumstances from an independent tax advisor concerning the tax benefits to him of the deduction for Intangible Drilling Costs in the Partnership in which he invests. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 16 Drilling Contracts. Each Partnership will enter into the Drilling and Operating Agreement with the Managing General Partner or its Affiliates, acting as a third-party general drilling contractor, to drill and complete the Partnership's development wells on a Cost plus 15% basis. For its services as general drilling contractor, the Managing General Partner anticipates that on average over all of the wells drilled and completed by each Partnership, assuming a 100% Working Interest in each well, it will have reimbursement of general and administrative overhead of approximately $12,690 per well and a profit of 15% (approximately $23,976) per well, with respect to the Intangible Drilling Costs and the portion of Tangible Costs paid by the Participants in each Partnership as described in "Compensation - Drilling Contracts" in the Prospectus. However, the actual cost of drilling and completing the wells may be more or less than the estimated amount, due primarily to the uncertain nature of drilling operations. Therefore, the Managing General Partner's 15% profit per well as described above also could be more or less than the dollar amount estimated by the Managing General Partner. The Managing General Partner believes the prices under the Drilling and Operating Agreement are competitive in the proposed areas of operation. Nevertheless, the amount of the profit realized by the Managing General Partner under the Drilling and Operating Agreement could be challenged by the IRS as being unreasonable and disallowed as a deductible Intangible Drilling Cost. (See "- Intangible Drilling Costs," above, and "Compensation" and "Proposed Activities" in the Prospectus.) Depending primarily on when each Partnership's subscription proceeds are received, the Managing General Partner anticipates that either or both of the Partnerships may prepay in 2005 most, if not all, of their respective Intangible Drilling Costs for drilling activities that will begin in 2006. (See "- 2005 Expenditures," above.) In Keller v. Commissioner, 79 T.C. 7 (1982), aff'd 725 F.2d 1173 (8th Cir. 1984), the Tax Court applied a two-part test for the current deductibility of prepaid intangible drilling and development costs. The test is: o the expenditure must be a payment rather than a refundable deposit; and o the deduction must not result in a material distortion of income taking into substantial consideration the business purpose aspects of the transaction. The drilling partnership in Keller entered into footage and daywork drilling contracts which permitted it to terminate the contracts at any time without default by the driller, and receive a return of the prepaid amounts less amounts earned by the driller. The Tax Court found that the right to receive, by unilateral action, a refund of the prepayments on the footage and daywork drilling contracts rendered the prepayments deposits instead of payments. Therefore, the prepayments were held to be nondeductible in the year they were paid to the extent they had not been earned by the driller. The Tax Court further found that the drilling partnership failed to show a convincing business purpose for prepayments under the footage and daywork drilling contracts. The drilling partnership in Keller also entered into turnkey drilling contracts which permitted it to stop work under the contract at any time and apply the unearned balance of the prepaid amounts to another well to be drilled on a turnkey basis. The Tax Court found that these prepayments constituted "payments" and not nondeductible deposits, despite the right of substitution. Further, the Tax Court noted that the turnkey drilling contracts obligated "the driller to drill to the contract depth for a stated price regardless of the time, materials or expenses required to drill the well," thereby locking in prices and shifting the risks of drilling from the drilling partnership to the driller. Since the drilling partnership, a cash basis taxpayer, received the benefit of the turnkey obligation in the year of prepayment, the Tax Court found that the amounts prepaid on turnkey drilling contracts clearly reflected income and were deductible in the year of prepayment. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 17 In Leonard T. Ruth, TC Memo 1983-586, a drilling program entered into nine separate turnkey contracts with a general contractor, the parent corporation of the drilling program's corporate general partner, to drill nine program wells. Each contract identified the prospect to be drilled, stated the turnkey price, and required the full price to be paid in 1974. The program paid the full turnkey price to the general contractor on December 31, 1974; the receipt of which was found by the court to be significant in the general contractor's financial planning. The program had no right to receive a refund of any of the payments. The actual drilling of the nine wells was subcontracted by the general contractor to independent contractors who were paid by the general contractor in accordance with their individual contracts. The drilling of all wells commenced in 1975 and all wells were completed that year. The amount paid by the general contractor to the independent driller for its work on the nine wells was approximately $365,000 less than the amount prepaid by the program to the general contractor. The program claimed a deduction for intangible drilling and development costs in 1974. The IRS challenged the timing of the deduction, contending that there was no business purpose for the payments in 1974, that the turnkey arrangements were merely "contracts of convenience" designed to create a tax deduction in 1974, and that the turnkey contracts constituted assets having a life beyond the taxable year and that to allow a deduction for their entire costs in 1974 distorted income. The Tax Court, relying on Keller, held that the program could deduct the full amount of the payments in 1974. The court found that the program entered into turnkey contracts, paid a premium to secure the turnkey obligations, and thereby locked in the drilling price and shifted the risks of drilling to the general contractor. Further, the court found that by signing and paying the turnkey obligation, the program got its bargained-for benefit in 1974, therefore the deduction of the payments in 1974 clearly reflected income. Each Partnership will attempt to comply with the guidelines set forth in Keller with respect to any prepaid Intangible Drilling Costs. The Drilling and Operating Agreement will require each Partnership to prepay in 2005 all of the Partnership's share of the estimated Intangible Drilling Costs, and all of the Participants' share of the Partnership's share of the estimated Tangible Costs, for drilling and completing specified wells, the drilling of which may begin in 2006. These prepayments of Intangible Drilling Costs should not result in a loss of a current deduction for the Intangible Drilling Costs if: o there is a legitimate business purpose for the required prepayment; o the contract is not merely a sham to control the timing of the deduction; and o there is an enforceable contract of economic substance. The Drilling and Operating Agreement will require each Partnership to prepay the Managing General Partner's estimate of the Intangible Drilling Costs and the Participants' share of the Tangible Costs to drill and complete the wells specified in the Drilling and Operating Agreement in order to enable the Operator to: o begin site preparation for the wells; o obtain suitable subcontractors at the then current prices; and o insure the availability of equipment and materials. Under the Drilling and Operating Agreement excess prepaid Intangible Drilling Costs, if any, will not be refundable to a Partnership, but instead will be applied only to Intangible Drilling Cost overruns, if any, on the other specified wells being drilled or completed by the Partnership or to Intangible Drilling Costs to be incurred by the Partnership in drilling and completing substitute wells. Under Keller, a provision for substitute wells should not result in the prepayments being characterized as refundable deposits. The likelihood that prepayments of Intangible Drilling Costs will be challenged by the IRS on the grounds that there is no business purpose for the prepayments is increased if prepayments are not required with respect to 100% of the Working Interest in the well. In this regard, the Managing General Partner anticipates that less than 100% of the Working Interest will be acquired by each Partnership in one or more of its wells, and prepayments of Intangible Drilling Costs will not be required of the other owners of Working Interests in those wells. In our view, however, a legitimate business purpose for the required prepayments of Intangible Drilling Costs by the Partnerships may exist under the guidelines set forth in Keller, even though prepayments are not required by the drilling contractor with respect to a portion of the Working Interest in the wells. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 18 In addition, a current deduction for prepaid Intangible Drilling Costs is available only if the drilling of the wells begins before the close of the 90th day after the close of the taxable year in which the prepayment was made. I.R.C. ss.461(i). (See "- Method of Accounting," above.) Therefore, under each Partnership's Drilling and Operating Agreement, the Managing General Partner as operator and general drilling contractor must begin drilling each of the prepaid wells, if any, of both partnerships before the close of the 90th day after the close of the Partnership's taxable year in which the prepayment was made, which is March 31, 2006 for both Partnerships. However, the drilling of any Partnership Well may be delayed due to circumstances beyond the control of the Managing General Partner or the drilling subcontractors. These circumstances include, for example: o the unavailability of drilling rigs; o decisions of third-party operators to delay drilling the wells; o poor weather conditions; o inability to obtain drilling permits or access right to the drilling site; or o title problems; and the Managing General Partner will have no liability to any Partnership or its Participants if these types of events delay beginning the drilling of the prepaid wells past the close of the 90th day after the close of the Partnership's taxable year (i.e., March 31, 2006). If the drilling of a prepaid Partnership Well in a Participant's Partnership does not begin on or before the close of the 90th day after the close of the Partnership's taxable year in which the prepayment was made (i.e., March 31, 2006), deductions claimed by a Participant in that Partnership for prepaid Intangible Drilling Costs for the well in 2005, the year in which the Participant invested in the Partnership, would be disallowed and deferred to the next taxable year, 2006, when the well is actually drilled. If there is an audit of a Partnership's federal information income tax return, the IRS may disallow the current deductibility of a portion or all of any prepaid Intangible Drilling Costs under the Partnership's drilling contracts, thereby decreasing the amount of the Participants' deductions for 2005, the year in which they invested in the Partnership, and the challenge may ultimately be sustained by the courts if litigated. In the event of disallowance, the deduction for prepaid Intangible Drilling Costs would be available in the next year, 2006, when the wells are actually drilled. Depletion Allowance. Proceeds from the sale of each Partnership's natural gas and oil production will constitute ordinary income. A certain portion of that income will not be taxable under the depletion allowance which permits the deduction from gross income for federal income tax purposes of either the percentage depletion allowance or the cost depletion allowance, whichever is greater. I.R.C. ss.ss.611, 613 and 613A. These deductions are subject to recapture as ordinary income rather than capital gain on the sale or other taxable disposition of the property or a Participant's Units. (See " - Sale of the Properties" and " - Disposition of Units," below.) Cost depletion for any year is determined by dividing the adjusted tax basis for the property by the total units of natural gas or oil expected to be recoverable from the property and then multiplying the resultant quotient by the number of units actually sold during the year. Cost depletion cannot exceed the adjusted tax basis of the property to which it relates. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 19 Percentage depletion generally is available to taxpayers other than "integrated oil companies" as that term is defined in "- Intangible Drilling Costs," above, which does not include the Partnerships. Percentage depletion is based on a Participant's share of his Partnership's gross production income from its natural gas and oil properties. Generally, percentage depletion is available with respect to 6 million cubic feet of average daily production of domestic natural gas or 1,000 barrels of average daily production of domestic crude oil. Taxpayers who have both natural gas and oil production may allocate the production limitation between the production. The rate of percentage depletion is 15%. However, percentage depletion for marginal production increases 1%, up to a maximum increase of 10%, for each whole dollar that the domestic wellhead price of crude oil for the immediately preceding year is less than $20 per barrel without adjustment for inflation. I.R.C. ss.613A(c)(6). The term "marginal production" includes natural gas and oil produced from a domestic stripper well property, which is defined in ss.613A(c)(6)(E) of the Code as any property which produces a daily average of 15 or less equivalent barrels of oil, which is equivalent to 90 mcf of natural gas, per producing well on the property in the calendar year. The Managing General Partner has represented that most, if not all, of the natural gas and oil production from each Partnership's productive wells will be marginal production under this definition in the Code. Therefore, most, if not all, of each Partnership's gross income from the sale of its natural gas and oil production will qualify for these potentially higher rates of percentage depletion. The rate of percentage depletion for marginal production in 2005 is 15%. This rate may fluctuate from year to year depending on the price of oil, but will not be less than the statutory rate of 15% nor more than 25%. Also, percentage depletion: (i) may not exceed 100% of the net income from each natural gas and oil property before the deduction for depletion, however, this limitation is suspended in 2005 with respect to marginal properties (see I.R.C. ss.613A (c)(6)(H)), which the Managing General Partner has represented will include most, if not all, of each Partnership's wells; and (ii) is limited to 65% of the taxpayer's taxable income for a year computed without regard to percentage depletion, net operating loss carry-backs and capital loss carry-backs. Availability of percentage depletion must be computed separately by each Participant and not by a Partnership or for Participants in a Partnership as a whole. Potential Participants are urged to seek advice based on their particular circumstances from an independent tax advisor with respect to the availability of percentage depletion to them. Marginal Well Production Credits. Under the American Jobs Creation Act of 2004, beginning in 2005 there is a marginal well production credit of 50(cent) per mcf of qualified natural gas production and $3 per barrel of qualified oil production for purposes of the regular federal income tax. This credit is part of the general business credit under ss.38 of the Code, but is not one of the specified energy credits which can be used against the alternative minimum tax. (See " - Alternative Minimum Tax," below.) Because natural gas and oil production which qualifies as marginal production under the percentage depletion rules discussed above, which the Managing General Partner has represented will include most, if not all, of the natural gas and oil production from each Partnership's productive wells, is also qualified marginal production for purposes of this credit, the natural gas and oil production from most, if not all, of each Partnership's wells will also be eligible for this credit. To the extent a Participant's share of his Partnership's marginal well production credits, if any, exceeds the Participant's regular federal income tax owed on his share of his Partnership's taxable income, the excess credits, if any, can be used by the Participant to offset any other regular federal income taxes owed by the Participant, on a dollar-for-dollar basis, subject to certain limitations, including the passive activity loss limitation in the case of Limited Partners. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 20 The marginal well production credit under ss.45I of the Code for any tax year will be an amount equal to the product of: o the credit amount; and o the qualified natural gas production and the qualified crude oil production which is attributable to the taxpayer. Also, the marginal well production credit does not reduce any otherwise allowable deduction (e.g. depletion) or reduce the taxpayer's adjusted basis in the qualified marginal well. The credit will be reduced proportionately for reference prices between $1.67 and $2.00 per mcf for natural gas and $15 and $18 per barrel for oil. The applicable reference price for a tax year is the reference price of the calendar year preceding the calendar year in which the tax year begins. Thus, the reference prices are determined on a one-year look-back basis. In this regard, the reference price for oil was $27.56 in 2003 (IRS Notice 2004-33, I.R.B. 2004-18), and it has not been under the $18.00 threshold necessary to qualify for any marginal well production credit for oil since 1999. Similarly, the Managing General Partner received an average selling price after deducting all expenses, including transportation expenses, of approximately $4.78 per mcf in 2003, and the average price it has received for natural gas production in each calendar year since 1999 has not been less than the $3.30 it received in 2000. In this regard, the Managing General Partner has represented that it does not anticipate that any of the Partnerships' production of natural gas and oil from their respective wells in 2005, if any, will qualify for the marginal well production credit in 2005, because the prices for natural gas and oil in 2004 were substantially above the $2.00 per mcf of natural gas and $18.00 per barrel of oil prices where the credit phases out completely. Based on the prices set forth in "Proposed Activities - Sale of Natural Gas and Oil Production" in the Prospectus for natural gas and oil in the past several years, it may appear unlikely that a Partnership's natural gas and oil production will ever qualify for this credit. However, prices for natural gas and oil are volatile and could decrease in the future. (See "Risk Factors - Risks Related To The Partnerships' Oil and Gas Operations - Partnership Distributions May be Reduced if There is a Decrease in the Price of Natural Gas and Oil," in the Prospectus.) Thus, it is possible that the Partnerships' production of natural gas or oil in one or more taxable years after 2005 could qualify for the marginal well production credit, depending primarily on the applicable reference prices for natural gas and oil in the future. A qualified marginal well is a well which is located in the United States or its possessions: o the production from which during the tax year is treated as marginal production under the percentage depletion rules of ss.613A(c)(6) of the Code; or o which, during the tax year, in the case of a natural gas well, has average daily production of not more than 25 barrel-of-oil equivalents, and produces water at a rate not less than 95% of total well effluent. For purposes of the percentage depletion rules, ss.613A(c)(6)(D) of the Code defines "marginal production" as domestic natural gas or crude oil produced from a property that is: o a stripper well property (i.e. a property which has average daily production of 15 or less barrel equivalents of natural gas and oil per well, based on all of the producing wells on the property); or o a heavy oil property. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 21 As noted above, ss.45I(c)(3)(A)(i) of the Code incorporates the definition of marginal property that is used for purposes of the increased percentage depletion rate that applies when the reference price of crude oil is less than $20. Therefore, any property that qualifies for the increased percentage depletion rate may also qualify for this credit. The same definition of marginal property also applies for purposes of the suspension in 2005 of the 100%-of-taxable income limitation on percentage depletion for oil and gas produced from marginal properties. (See "- Depletion Allowance," above.) The maximum amount of marginal production of natural gas and oil from a well on which the credit can be claimed by a Partnership in any taxable year is 1,095 barrels of oil or barrel-of-oil equivalents per well. For a well which is not capable of production during each day of a tax year, the 1,095 barrel limitation for oil and the barrel-of-oil equivalent limitation for natural gas for each well will be proportionately reduced to reflect the ratio which the number of days of production bears to the total number of days in the tax year. Under ss.613A(e)(4) of the Code, a "barrel" of oil means 42 U.S. gallons. Under ss.29(d)(5) of the Code, the term "barrel-of-oil equivalent" means that amount of fuel which has a Btu ("British thermal unit") content of 5.8 million. Therefore, the maximum barrel-of-oil equivalent of natural gas per well for which the credit is available is 6,351,000,000 Btus (1,095 barrels of oil x 5,800,000 Btus). These Btus must be converted to mcfs, since the credit is based on mcfs. According to the Energy Information Administration, one cubic foot of natural gas is approximately equal to 1,021 Btus. Using this conversion ratio, the number of cubic feet of natural gas in 6,351,000,000 Btus is approximately 6,220,372 (6,351,000,000 / 1,021) cubic feet of natural gas. Since the credit will be 50(cent) per 1,000 cubic feet ("mcf") of natural gas, this amount is rounded down to 6,220,000 cubic feet of natural gas (6,220 mcf). Under this example, the well could produce a little more than an average of 17 mcf of natural gas per day (6,220 mcf / 365 days= 17.04 mcf of natural gas per day) that may qualify for the marginal well production credit. Subject to a post-2005 inflation adjustment, the maximum dollar amount of the credit in any tax year will be $3,110 (6,220 mcf x 50(cent)) for qualified natural gas production from each qualified marginal well, as explained above, and $3,285 ($3.00 x 1,095 barrels) for qualified crude oil production from each qualified marginal well. There is no limit on the number of qualified marginal wells on which a Partnership and its Participants can claim the credit. Only holders of a Working Interest in a qualified well can claim the credit. For purposes of the credit, the Participants in a Partnership will be treated as Working Interest owners because of their flow-through ownership interest in the Partnership. In this regard, the Managing General Partner has represented that each Partnership will own only Working Interests in all of its Prospects. As a result of this rule, owners of non-Working Interests in a well, such as the owner of a Landowner's Royalty Interest, will not receive any of these credits from the well. For a qualified marginal well in which there is more than one owner of the Working Interests, which will be the case for one or more wells in each Partnership, if the natural gas or oil production from the well exceeds the 1,095 barrel limitation for oil or the barrel-of-oil equivalent for natural gas (determined at the Partnership level, and not the Participant level), then the amount of qualifying natural gas and oil production that each owner of a partial Working Interest in the well is entitled to will be based on the ratio which each Working Interest owner's revenue interest in the production from the well bears to the aggregate of the revenue interests of all Working Interest owners in the production from the well. (See "Proposed Activities - Interests of Parties" in the Prospectus.) Each Participant in a Partnership will share in his Partnership's marginal well production credits, if any, in the same proportion as his share of the Partnership's production revenues. (See "Participation in Costs and Revenues" in the Prospectus.) Unused marginal natural gas and oil well production credits can be carried back for up to five years. Also, the carryforward period for marginal natural gas and oil well production credits is 20 years, the same as for other general business credits. However, unlike many other credits that comprise the general business credit under ss.38 of the Code, the marginal well production credit is not a "qualified business credit" under ss.196(c) of the Code. Thus, a Participant will not be able to deduct any marginal well production credits under ss.196 of the Code that remain unused at the end of the twenty-year carryforward period. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 22 Under ss.469(c)(3) of the Code, an Investor General Partner's share of his Partnership's marginal well production credits, if any, will be an active credit which may offset the Investor General Partner's regular federal income tax liability on any type of income. However, after the Investor General Partner is converted to a Limited Partner in his Partnership, his share of the Partnership's marginal well production credits, if any, will be active credits only to the extent of the converted Investor General Partner's regular federal income tax liability which is allocable to his share of any net income of his Partnership, which is still treated as non-passive income even after the Investor General Partner has been converted to a Limited Partner. (See " - Conversion from Investor General Partner to Limited Partner," above.) Any excess credits allocable to the converted Investor General Partner, as well as all of the marginal well production credits allocable to those investors who originally invest in a Partnership as Limited Partners, will be passive credits which can reduce only an investor's regular income tax liability attributable to passive income from the Partnership or other passive activities. Depreciation - Modified Accelerated Cost Recovery System ("MACRS"). Tangible Costs and the related depreciation deductions of each Partnership generally are charged and allocated under the Partnership Agreement 66% to the Managing General Partner and 34% to the Participants in the Partnership. However, if the total Tangible Costs for all of the Partnership's wells that would otherwise be charged to the Participants exceeds an amount equal to 10% of the Partnership's subscription proceeds, then the excess Tangible Costs, together with the related depreciation deductions, will be charged and allocated to the Managing General Partner. Most of each Partnership's equipment costs will be recovered through depreciation deductions over a seven year cost recovery period using the 200% declining balance method, with a switch to straight-line to maximize the deduction, beginning in the taxable year the equipment is placed in service by the Partnership. I.R.C. ss.168(c). In the case of a short tax year the MACRS deduction is prorated on a 12-month basis. No distinction is made between new and used property and salvage value is disregarded. All property assigned to the 7-year class generally is treated as placed in service, or disposed of, in the middle of the year. All of these cost recovery deductions claimed by the Partnerships and their respective Participants are subject to recapture as ordinary income rather than capital gain on the sale or other taxable disposition of the property or a Participant's Units. (See "- Sale of the Properties" and "- Disposition of Units," below.) Depreciation for alternative minimum tax purposes is computed using the 150% declining balance method, switching to straight-line, for most personal property. This means that a Partnership's depreciation deductions in its early years for alternative minimum tax purposes will be less than the Partnership's depreciation deductions in those years for regular tax purposes, and greater in the Partnership's later years. This will result in adjustments in computing the alternative minimum taxable income of each of the Partnership's Participants. (See " - Alternative Minimum Tax," below.) Lease Acquisition Costs and Abandonment. Lease acquisition costs, together with the related cost depletion deduction and any abandonment loss for Lease costs, are allocated under the Partnership Agreement 100% to the Managing General Partner, which will contribute the Leases to each Partnership as a part of its Capital Contribution. Tax Basis of Units. A Participant's share of his Partnership's losses is allowable only to the extent of the adjusted basis of his Units at the end of the Partnership's taxable year. I.R.C. ss.704(d). The adjusted basis of the Participant's Units will be adjusted, but not below zero, for any gain or loss to the Participant from a sale or other taxable disposition by the Partnership of a natural gas and oil property, and will be increased by his: (i) cash subscription payment; (ii) share of Partnership income; and (iii) share, if any, of Partnership debt. The adjusted basis of a Participant's Units will be reduced by his: KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 23 (i) share of Partnership losses; (ii) share of Partnership expenditures that are not deductible in computing its taxable income and are not properly chargeable to capital account; (iii) depletion deductions, but not below zero; and (iv) cash distributions from the Partnership. I.R.C. ss.ss.705, 722 and 742. The reduction in a Participant's share of Partnership liabilities, if any, is considered a cash distribution to the Participant. Although Participants will not be personally liable on any Partnership loans, Investor General Partners will be liable for other obligations of the Partnership. (See "Risk Factors - Risks Related to an Investment In a Partnership - If You Choose to Invest as a General Partner, Then You Have Greater Risk Than a Limited Partner" in the Prospectus.) Should cash distributions to a Participant from his Partnership exceed the tax basis of the Participant's Units, taxable gain would result to the Participant to the extent of the excess. (See "- Distributions From a Partnership," below.) "At Risk" Limitation For Losses. Subject to the limitations on "passive losses" generated by a Partnership in the case of Limited Partners, and a Participant's basis in his Units, each Participant generally may use his share of the Partnership's losses to offset income from other sources. (See "- Limitations on Passive Activities" and "- Tax Basis of Units," above.) However, a Participant, other than a corporation which is neither an S corporation nor a corporation in which five or fewer individuals own more than 50% of the stock, who sustains a loss in connection with a Partnership's natural gas and oil activities may deduct the loss only to the extent of the amount he has "at risk" in the Partnership at the end of a taxable year. I.R.C. ss.465. "Loss" means the excess of allowable deductions for a taxable year from a Partnership over the amount of income actually received or accrued by the Participant during the year from the Partnership. A Participant's initial "at risk" amount generally is limited to the amount of money he pays for his Units. However, any amounts borrowed by a Participant to buy his Units will not be considered "at risk" if the amounts are borrowed from any Person who has an interest, other than as a creditor, in the Partnership or from a related person to a person, other than the Participant, having such an interest. In this regard, the Managing General Partner has represented that it and its Affiliates will not make or arrange financing for potential Participants to use to purchase Units in a Partnership. Also, the amount a Participant has "at risk" in a Partnership may not include the amount of any loss that the Participant is protected against through: o nonrecourse loans; o guarantees; o stop loss agreements; or o other similar arrangements. The amount of any loss that is disallowed will be carried over to the next taxable year, to the extent a Participant is "at risk" in the Partnership. Further, a Participant's "at risk" amount in subsequent taxable years of the Partnership will be reduced by that portion of the loss which is allowable as a deduction. Since income, gains, losses, and distributions of the Partnership affect the "at risk" amount, the extent to which a Participant is "at risk" must be determined annually. Previously allowed losses must be included in gross income if the "at risk" amount is reduced below zero. The amount included in income, however, may be deducted in the next taxable year to the extent of any increase in the amount which the Participant has "at risk" in the Partnership. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 24 Distributions From a Partnership. Generally, a cash distribution from a Partnership to a Participant in excess of the adjusted basis of the Participant's Units immediately before the distribution is treated as gain to the Participant from the sale or exchange of his Units to the extent of the excess. I.R.C. ss.731(a)(1). No loss is recognized by the Participants on these types of distributions. I.R.C. ss.731(a)(2). No gain or loss is recognized by the Partnership on these types of distributions. I.R.C. ss.731(b). If property is distributed by the Partnership to the Managing General Partner and the Participants, certain basis adjustments may be made by the Partnership, the Managing General Partner and the Participants. I.R.C. ss.ss.732, 733, 734, and 754. (See ss.5.04(d) of the Partnership Agreement and "- Tax Elections," below.) Other distributions of cash, disproportionate distributions of property, if any, and liquidating distributions of a Partnership may result in taxable gain or loss to its Participants. (See "- Disposition of Units" and "- Termination of a Partnership," below.) Sale of the Properties. Under the Jobs and Growth Tax Relief Reconciliation Act of 2003 ("2003 Tax Act"), the maximum tax rates on a noncorporate taxpayer's adjusted net capital gain on the sale of assets held more than a year of 20%, or 10% to the extent it would have been taxed at a 10% or 15% rate if it had been ordinary income, have been reduced to 15% and 5%, respectively, for most capital assets sold or exchanged after May 5, 2003. In addition, for 2008 only, the 5% tax rate on adjusted net capital gain is reduced to 0%. The 2003 Tax Act also eliminated the former maximum tax rates of 18% and 8%, respectively, on qualified five-year gain. I.R.C. ss.1(h). The new capital gain rates also apply for purposes of the alternative minimum tax. I.R.C. ss.55(b)(3). (See "- Alternative Minimum Tax," below.) However, the former tax rates are scheduled to be reinstated January 1, 2009, as if the 2003 Tax Act had never been enacted. "Adjusted net capital gain" means net capital gain, less certain types of net capital gain that are taxed a maximum rate of 28% (such as gain on the sale of most collectibles and gain on the sale of certain small business stock); or 25% (gain attributable to real estate depreciation). "Net capital gain" means the excess of net long-term gain (excess of long-term gains over long-term losses) over net short-term loss (excess of short-term gains over short-term losses). The annual capital loss limitation for noncorporate taxpayers is the amount of capital gains plus the lesser of $3,000, which is reduced to $1,500 for married persons filing separate returns, or the excess of capital losses over capital gains. I.R.C. ss.1211(b). Gains and losses from sales of natural gas and oil properties held for more than 12 months generally will be treated as a long-term capital gain, while a net loss will be an ordinary deduction, except to the extent of depreciation recapture on equipment and recapture of Intangible Drilling Costs and depletion deductions as discussed below. In addition, gain on the sale of a Partnership's natural gas and oil properties may be recaptured as ordinary income to the extent of certain losses for the five most recent preceding taxable years on previous sales, if any, of the Partnership's natural gas and oil properties or other assets. I.R.C. ss.1231(c). Other gains and losses on sales of natural gas and oil properties will generally result in ordinary gains or losses. Intangible Drilling Costs and depletion allowances that are incurred in connection with a natural gas or oil property may be recaptured as ordinary income when the property is sold or otherwise disposed of in a taxable transaction by a Partnership. Generally, the amount recaptured is the lesser of: o the aggregate amount of expenditures which have been deducted as Intangible Drilling Costs with respect to the property and which, but for being deducted, would have been included in the adjusted basis of the property, plus deductions for depletion which reduced the adjusted basis of the property; or o the excess of: o the amount realized, in the case of a sale, exchange or involuntary conversion; or o the fair market value of the interest, in the case of any other taxable disposition; over the adjusted basis of the property. I.R.C. ss.1254(a). KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 25 (See "- Intangible Drilling Costs" and "- Depletion Allowance," above.) In addition, all gain on the sale or other taxable disposition of equipment is treated as ordinary income to the extent of MACRS deductions claimed by the Partnership. I.R.C. ss. 1245(a). (See "- Depreciation - Modified Accelerated Cost Recovery System ("MACRS"), above.) Disposition of Units. The sale or exchange, including a purchase by the Managing General Partner, of all or some of a Participant's Units held by him for more than 12 months generally will result in a recognition by the Participant of long-term capital gain or loss. However, previous deductions for depreciation, depletion and Intangible Drilling Costs, and the Participant's share of the Partnership's "ss.751 assets" (i.e. inventory and unrealized receivables), may be recaptured as ordinary income rather than capital gain regardless of how long the Participant has owned his Units. (See "- Sale of the Properties," above.) If the Units are held for 12 months or less, the gain or loss generally will be short-term gain or loss. Also, a Participant's pro rata share of his Partnership's liabilities, if any, as of the date of the sale or exchange must be included in the amount realized. Therefore, the gain recognized by a Participant may result in a tax liability to the Participant greater than the cash proceeds, if any, received by the Participant from the disposition. In addition to gain from a passive activity, a portion of any gain recognized by a Limited Partner on the sale or other taxable disposition of his Units will be characterized as portfolio income under ss.469 of the Code to the extent the gain is attributable to portfolio income, e.g. interest income on investments of working capital. Treas. Reg. ss.1.469-2T(e)(3). (See "- Limitations on Passive Activities," above.) A gift of a Participant's Units may result in federal and/or state income tax and gift tax liability to the Participant. Also, interests in different partnerships do not qualify for tax-free like-kind exchanges. I.R.C. ss.1031(a)(2)(D). Other dispositions of a Participant's Units may or may not result in recognition of taxable gain. However, no gain should be recognized by an Investor General Partner on the conversion of his Investor General Partner Units to Limited Partner Units so long as there is no change in his share of his Partnership's liabilities or certain Partnership assets as a result of the conversion. Rev. Rul. 84-52, 1984-1 C.B. 157. A Participant who sells or exchanges all or some of his Units is required by the Code to notify his Partnership within 30 days or by January 15 of the following year, if earlier. I.R.C. ss.6050K. After receiving the notice, the Partnership is required to make a return with the IRS stating the name and address of the transferor and the transferee, the fair market value of the portion of the Partnership's unrealized receivables and appreciated inventory allocable to the Units sold or exchanged (which is subject to recapture as ordinary income instead of capital gain) and any other information as may be required by the IRS. The Partnership must also provide each person whose name is set forth in the return a written statement showing the information set forth on the return. If a Participant dies, or sells or exchanges all of his Units, the taxable year of his Partnership will close with respect to that Participant, but not the remaining Participants, on the date of death, sale or exchange, with a proration of partnership items for the Partnership's taxable year. I.R.C. ss.706(c)(2). If a Participant sells less than all of his Units, the Partnership's taxable year will not terminate with respect to the selling Participant, but his proportionate share of the Partnership's items of income, gain, loss, deduction and credit will be determined by taking into account his varying interests in the Partnership during the taxable year. Deductions and tax credits generally may not be allocated to a person acquiring Units from a selling Participant for a period before the purchaser's admission to the Partnership. I.R.C. ss.706(d). Participants are urged to seek advice based on their particular circumstances from an independent tax advisor before any disposition of a Unit, including any purchase of the Unit by the Managing General Partner. Alternative Minimum Tax. With limited exceptions, taxpayers must pay an alternative minimum tax if it exceeds the taxpayer's regular federal income tax for the year. I.R.C. ss.55. For noncorporate taxpayers, the alternative minimum tax is imposed on alternative minimum taxable income that is above the exemption amounts set forth below. Alternative minimum taxable income generally is taxable income, plus or minus various adjustments, plus tax preference items. The tax rate for noncorporate taxpayers is 26% for the first $175,000, $87,500 for married individuals filing separately, of a taxpayer's alternative minimum taxable income in excess of the exemption amount; and additional alternative minimum taxable income is taxed at 28%. However, the regular tax rates on capital gains also will apply for purposes of the alternative minimum tax. (See "- Sale of the Properties," above.) KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 26 Subject to the phase-out provisions summarized below, the exemption amounts for 2005 are $58,000 for married individuals filing jointly and surviving spouses, $40,250 for single persons other than surviving spouses, and $29,000 for married individuals filing separately. For years beginning after 2005, these exemption amounts are scheduled to decrease to $45,000 for married individuals filing jointly and surviving spouses, $33,750 for single persons other than surviving spouses, and $22,500 for married individuals filing separately. The exemption amount for estates and trusts is $22,500 in 2005 and subsequent years. The exemption amounts set forth above are reduced by 25% of alternative minimum taxable income in excess of: o $150,000, in the case of married individuals filing a joint return and surviving spouses - the $58,000 exemption amount is completely phased out when alternative minimum taxable income is $382,000 or more, and the $45,000 amount phases out completely at $330,000; o $112,500, in the case of unmarried individuals other than surviving spouses - the $40,250 exemption amount is completely phased out when alternative minimum taxable income is $273,500 or more, and the $33,750 amount phases out completely at $247,500; and o $75,000, in the case of married individuals filing a separate return - the $29,000 exemption amount is completely phased out when alternative minimum taxable income is $191,000 or more and the $22,500 amount phases out completely at $165,000. In addition, in 2005 the alternative minimum taxable income of married individuals filing separately is increased by the lesser of $29,000 ($22,500 after 2005) or 25% of the excess of the person's alternative minimum taxable income (determined without regard to this provision) over $191,000 ($165,000 after 2005). Some of the principal adjustments to taxable income that are used to determine alternative minimum taxable income include those summarized below: o Depreciation deductions of the costs of the equipment in the wells ("Tangible Costs") may not exceed deductions computed using the 150% declining balance method.(See "- Depreciation - Modified Accelerated Cost Recovery System ("MACRS")," above.) o Miscellaneous itemized deductions are not allowed. o Medical expenses are deductible only to the extent they exceed 10% of adjusted gross income. o State and local property taxes and income taxes (or sales taxes, instead of state and local income taxes, at the taxpayer's election in the 2005 taxable year), which are itemized and deducted for regular tax purposes, are not deductible. o Interest deductions are restricted. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 27 o The standard deduction and personal exemptions are not allowed. o Only some types of operating losses are deductible. o Different rules under the Code apply to incentive stock options that may require earlier recognition of income. The principal tax preference items that must be added to taxable income for alternative minimum tax purposes include: o certain excess Intangible Drilling Costs, as discussed below; and o tax-exempt interest earned on certain private activity bonds. For taxpayers other than "integrated oil companies" as that term is defined in "- Intangible Drilling Costs," above, which does not include the Partnerships, the 1992 National Energy Bill repealed: o the preference for excess Intangible Drilling Costs; and o the excess percentage depletion preference for natural gas and oil. The repeal of the excess Intangible Drilling Costs preference, however, under current law may not result in more than a 40% reduction in the amount of the taxpayer's alternative minimum taxable income computed as if the excess Intangible Drilling Costs preference had not been repealed. I.R.C. ss.57(a)(2)(E). Under the prior rules, the amount of Intangible Drilling Costs which is not deductible for alternative minimum tax purposes is the excess of the "excess intangible drilling costs" over 65% of net income from natural gas and oil properties. Net natural gas and oil income is determined for this purpose without subtracting excess Intangible Drilling Costs. Excess Intangible Drilling Costs is the regular Intangible Drilling Costs deduction minus the amount that would have been deducted under 120-month straight-line amortization, or, at the taxpayer's election, under the cost depletion method. There is no preference item for costs of nonproductive wells. Also, each Participant may elect under ss.59(e) of the Code to capitalize all or part of his share of his Partnership's Intangible Drilling Costs and deduct the costs ratably over a 60-month period beginning with the month in which the costs were paid or incurred by the Partnership. This election also applies for regular tax purposes and can be revoked only with the IRS' consent. Making this election, therefore, generally will result in the following consequences to the Participant: o the Participant's regular tax deduction for Intangible Drilling Costs in the year in which he invests will be reduced because the Participant must spread the deduction for the amount of Intangible Drilling Costs which the Participant elects to capitalize over the 60-month amortization period; and o the capitalized Intangible Drilling Costs will not be treated as a preference that is included in the Participant's alternative minimum taxable income. Other than Intangible Drilling Costs as discussed above, the principal tax item that may have an impact on a Participant's alternative minimum taxable income as a result of investing in a Partnership is depreciation of the Partnership's equipment. As noted in " - Depreciation - Modified Accelerated Cost Recovery System ("MACRS")," above, each Partnership's cost recovery deductions for regular income tax purposes generally will be computed using the 200% declining balance method rather than the 150% declining balance method used for alternative minimum tax purposes. This means that in the early years of a Partnership a Participant's depreciation deductions from the Partnership generally will be smaller for alternative minimum tax purposes when compared to the Participant's depreciation deductions in those taxable years for regular income tax purposes on the same equipment. This, in turn, could cause a Participant to incur, or may increase, the Participant's alternative minimum tax liability in the Partnership's early years. Conversely, this adjustment may decrease the Participant's alternative minimum taxable income in the Partnership's later years. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 28 A Participant's share of his Partnership's marginal well production credits, if any, may not be used to reduce his alternative minimum tax liability, if any. Also, the rules relating to the alternative minimum tax for corporations are different from those summarized above. All prospective Participants contemplating purchasing Units in a Partnership are urged to seek advice based on their particular circumstances from an independent tax advisor as to the likelihood of them incurring or increasing any alternative minimum tax liability as a result of an investment in a Partnership. Limitations on Deduction of Investment Interest. Investment interest expense is deductible by a noncorporate taxpayer only to the extent of net investment income each year, with an indefinite carryforward of disallowed investment interest. I.R.C. ss.163. Investment interest expense generally includes all interest on debt not incurred in a person's active trade or business except consumer interest, qualified residence interest, and passive activity interest under ss.469 of the Code. Accordingly, an Investor General Partner's share of any interest expense incurred by the Partnership in which he invests before his Investor General Partner Units are converted to Limited Partner Units will be subject to the investment interest limitation. In addition, the Investor General Partner's share of the Partnership's income and losses, including the deduction for Intangible Drilling Costs, will be considered to be investment income and losses for purposes of this limitation. Thus, for example, a loss allocated to an Investor General Partner from the Partnership in the year in which he invests in the Partnership as a result of the deduction for Intangible Drilling Costs will reduce his net investment income and may reduce or eliminate the deductibility of his investment interest expenses, if any, in that taxable year with the disallowed portion to be carried forward to the next taxable year. Net investment income is the excess of investment income over investment expenses. Investment income generally includes: o gross income from interest, rents, and royalties; o any excess of net gain from dispositions of investment property over net capital gain determined by gains and losses from dispositions of investment property, and any portion of the net capital gain or net gain, if less, that the taxpayer elects to include in investment income; o portfolio income under the passive activity rules, which includes working capital investment income; o dividends that do not qualify to be taxed at capital gain rates and dividends that the taxpayer elects to treat as not qualified to be taxed at capital gain rates; and o income from a trade or business in which the taxpayer does not materially participate if the activity is not a "passive activity" under ss.469 of the Code. In the case of Investor General Partners, this includes the Partnership in which they invest before the conversion of Investor General Partner Units to Limited Partner Units in that Partnership, and possibly Partnership net income allocable to former Investor General Partners after they are converted to Limited Partners in that Partnership. Investment expenses include deductions, other than interest, that are directly connected with the production of net investment income, including actual depreciation or depletion deductions allowable. Investment income and investment expenses, however, do not include a Partnership's income or expenses taken into account in computing income or loss from a passive activity under ss.469 of the Code. (See "- Limitations on Passive Activities," above.) KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 29 Allocations. The Partnership Agreement allocates to each Participant his share of his Partnership's income, gains, losses, deductions, and credits, if any, including the deductions for Intangible Drilling Costs and depreciation. Allocations of certain items are made in ratios that are different than allocations of other items. (See "Participation in Costs and Revenues" in the Prospectus.) The Capital Accounts of each Participant in a Partnership generally will be adjusted to reflect his share of these allocations and the Participant's Capital Account, as adjusted, will be given effect in distributions made to the Participant on liquidation of the Partnership or the Participant's Units. Generally, the basis of the natural gas and oil properties owned by a Partnership for computation of cost depletion and gain or loss on disposition will be allocated and reallocated when necessary in the ratio in which the expenditure giving rise to the tax basis of each property was charged as of the end of the year. (See ss.5.03(b) of the Partnership Agreement.) Generally, a Participant's Capital Account in the Partnership in which he invests is increased by: o the amount of money he contributes to the Partnership; and o allocations of income and gain to him from the Partnership; and decreased by: o the value of property or cash distributed to him by the Partnership; and o allocations of losses and deductions to him by the Partnership. The regulations also require that there must be a reasonable possibility that the allocation will affect substantially the dollar amounts to be received by the partners from the partnership, independent of tax consequences. Allocations made in a manner that is disproportionate to the respective interests of the partners in a partnership of any item of partnership income, gain, loss, deduction or credit will not be given effect unless the allocation has "substantial economic effect." I.R.C. ss.704(b). An allocation generally will have economic effect if throughout the term of a partnership: o the partners' capital accounts are maintained in accordance with rules set forth in the regulations, which generally are based on tax accounting principles; o liquidation proceeds are distributed in accordance with the partners' capital accounts; and o any partner with a deficit balance in his capital account following the liquidation of his interest in the partnership is required to restore the amount of the deficit to the partnership. Even though the Participants in each Partnership are not required under the Partnership Agreement to restore deficit balances in their Capital Accounts with additional Capital Contributions, an allocation which is not attributable to nonrecourse debt still will be considered under the regulations to have economic effect to the extent it does not cause or increase a deficit balance in a Participant's Capital Account if: o the Partners' Capital Accounts are maintained in accordance with rules set forth in the regulations, which generally are based on tax accounting principles; o liquidation proceeds are distributed in accordance with the Partners' Capital Accounts; and KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 30 o the Partnership Agreement provides that a Participant who unexpectedly incurs a deficit balance in his Capital Account because of certain adjustments, allocations, or distributions will be allocated income and gain sufficient to eliminate the deficit balance as quickly as possible. Treas. Reg. ss.1.704-l(b)(2)(ii)(d). These provisions are included in the Partnership Agreement (See ss.ss.5.02, 5.03(h), and 7.02(a) of the Partnership Agreement.) Special provisions apply to deductions related to nonrecourse debt and tax credits, since allocations of these items cannot have substantial economic effect . If the Managing General Partner or an Affiliate makes a nonrecourse loan to a Partnership ("partner nonrecourse liability"), Partnership losses, deductions, or ss.705(a)(2)(B) expenditures attributable to the loan must be allocated to the Managing General Partner. Also, if there is a net decrease in partner nonrecourse liability minimum gain with respect to the loan, the Managing General Partner must be allocated income and gain equal to the net decrease. (See ss.ss.5.03(a)(1) and 5.03(i) of the Partnership Agreement.) In addition, any marginal well production credits of a Partnership will be allocated among the Managing General Partner and the Participants in the Partnership in accordance with their respective interests in the Partnership's production revenues from the sale of its natural gas and oil production. (See ss.5.03(g) of the Partnership Agreement.) In the event of a sale or transfer of a Participant's Unit, the death of a Participant, or the admission of an additional Participant, a Partnership's income, gain, loss, credits and deductions generally will be allocated among its Participants according to their varying interests in the Partnership during the taxable year. In addition, in certain circumstances the Code may require Partnership property to be revalued on the admission of additional Participants, or if certain distributions are made to the Participants. (See "- Tax Elections," below.) It should also be noted that each Participant's share of items of income, gain, loss, deduction and credit in the Partnership in which he invests must be taken into account by him whether or not he receives any cash distributions from the Partnership. For example, a Participant's share of Partnership revenues applied by his Partnership to the repayment of loans or the reserve for plugging wells will be included in his gross income in a manner analogous to an actual distribution of the revenues (and income) to him. Thus, a Participant may have tax liability on taxable income from his Partnership for a particular year in excess of any cash distributions from the Partnership to him with respect to that year. To the extent a Partnership has cash available for distribution, however, it is the Managing General Partner's policy that the Partnership's cash distributions to its Participants will not be less than the Managing General Partner's estimate of the Participants' income tax liability with respect to that Partnership's income. If any allocation under the Partnership Agreement is not recognized for federal income tax purposes, each Participant's share of the items subject to the allocation generally will be determined in accordance with his interest in the Partnership in which he invests by considering all of the relevant facts and circumstances. To the extent deductions or credits allocated by the Partnership Agreement exceed deductions or credits which would be allowed under a reallocation by the IRS, Participants may incur a greater tax burden. Partnership Borrowings. Under the Partnership Agreement the Managing General Partner and its Affiliates may make loans to the Partnerships. The use of Partnership revenues taxable to Participants to repay borrowings by their Partnership could create income tax liability for the Participants in excess of their cash distributions from the Partnership, since repayments of principal are not deductible for federal income tax purposes. In addition, interest on the loans will not be deductible unless the loans are bona fide loans that will not be treated as Capital Contributions to the Partnership by the Managing General Partner or its Affiliates in light of all of the surrounding facts and circumstances. In Revenue Ruling 72-135, 1972-1 C.B. 200, the IRS ruled that a nonrecourse loan from a general partner to a partnership engaged in natural gas and oil exploration represented a capital contribution by the general partner rather than a loan. Whether a "loan" by the Managing General Partner or its Affiliates to a Partnership represents in substance debt or equity is a question of fact to be determined from all the surrounding facts and circumstances. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 31 Partnership Organization and Offering Costs. Expenses connected with the offer and sale of Units in a Partnership, such as promotional expense, the Dealer-Manager fee, Sales Commissions, reimbursements to the Dealer-Manager and other selling expenses, professional fees, and printing costs, which are charged under the Partnership Agreement 100% to the Managing General Partner as Organization and Offering Costs, are not deductible. Although certain expenses incident to the creation of a partnership may be amortized over a period of not less than 180 months, these expenses also will be paid by the Managing General Partner as part of each Partnership's Organization and Offering Costs. Thus, any related deductions, which the Managing General Partner does not anticipate will be material in amount as compared to the total subscription proceeds of the Partnerships, will be allocated to the Managing General Partner. I.R.C. ss.709; Treas. Reg. ss.ss.1.709-1 and 2. Tax Elections. Each Partnership may elect to adjust the basis of its property (other than cash) on the transfer of a Unit in the Partnership by sale or exchange or on the death of a Participant, and on the distribution of property by the Partnership to a Participant (the ss.754 election).The general effect of this election is that transferees of the Units are treated, for purposes of depreciation and gain, as though they had acquired a direct interest in the Partnership assets and the Partnership is treated for these purposes, on certain distributions to the Participants, as though it had newly acquired an interest in the Partnership assets and therefore acquired a new cost basis for the assets. Any election, once made, may not be revoked without the consent of the IRS. In this regard, the Managing General Partner has represented that due to the complexities and added expense of the tax accounting required to implement a ss.754 election to adjust the basis of a Partnership's property when Units are sold, taking into account the limitations on the sale of the Partnership's Units, neither Partnership will make the ss.754 election. Even though the Partnerships will not make the ss.754 election, the basis adjustment described above is mandatory under the Code with respect to the transferee Partner only, if at the time a Unit is transferred by sale or exchange, or on the death of a Participant, the Partnership's adjusted basis in its property exceeds the fair market value of the property by more than $250,000 immediately after the transfer of the Unit. Similarly, a basis adjustment is mandatory under the Code if a partnership distributes property in-kind to a partner, (which the Partnerships generally will not do) and the sum of the partner's loss on the distribution and the basis increase to the distributed property is more than $250,000. I.R.C. ss.ss.734 and 743. If the basis of a Partnership's assets must be adjusted as discussed above,, the primary effect on the Partnership, other than the federal income tax consequences discussed above, would be an increase in its administrative and accounting expenses to make the required basis adjustments to its properties and separately account for those adjustments after they are made. In this regard, the Partnerships generally will not make in-kind property distributions to their respective Participants, and the Units have no readily available market and are subject to substantial restrictions on their transfer. (See "Transferability of Units - Restrictions on Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership Agreement" in the Prospectus.) These factors will tend to limit the additional expense to a Partnership if the mandatory basis adjustments to a Partnership's assets described above apply to it. In addition to the ss.754 election, each Partnership may make various elections under the Code for federal tax reporting purposes which could result in various items of income, gain, loss, deduction and credit being treated differently for tax purposes than for accounting purposes. Code ss.195 permits taxpayers to elect to capitalize and amortize "start-up expenditures" over a 180-month period. These items include amounts: o paid or incurred in connection with: o investigating the creation or acquisition of an active trade or business; o creating an active trade or business; or KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 32 o any activity engaged in for profit and for the production of income before the day on which the active trade or business begins, in anticipation of the activity becoming an active trade or business; and o which would be allowed as a deduction if paid or incurred in connection with the expansion of an existing business. Start-up expenditures do not include amounts paid or incurred in connection with the sale of the Units. If it is ultimately determined by the IRS or the courts that any of a Partnership's expenses constituted start-up expenditures, the Partnership's deductions for those expenses would be amortized over the 180-month period. Termination of a Partnership. Under ss.708(b) of the Code, a Partnership will be considered as terminated for federal income tax purposes if within a 12-month period there is a sale or exchange of 50% or more of the total interest in Partnership capital and profits. The closing of the Partnership year may result in more than 12 months' income or loss of the Partnership being allocated to certain Participants for the year of termination, for example, in the case of any Participants using fiscal years other than the calendar year. Under ss.731 of the Code, a Participant will realize taxable gain on a termination of a Partnership to the extent that money regarded as distributed to him by the Partnership exceeds the adjusted basis of his Units. The conversion of Investor General Partner Units to Limited Partner Units, however, will not terminate a Partnership. Rev. Rul. 84-52, 1984-1 C.B. 157. Also, due to the restrictions on transfers of Units in the Partnership Agreement, the Managing General Partner does not anticipate that either Partnership will ever be considered as terminated under ss.708(b) of the Code. Tax Returns and IRS Audits. The tax treatment of all partnership items generally is determined at the partnership, rather than the partner, level; and the partners generally are required to treat partnership items on their individual federal income tax returns in a manner which is consistent with the treatment of the partnership items on the partnership's federal information income tax return. I.R.C. ss.ss.6221 and 6222. Regulations define "partnership items" for this purpose as including distributive share items that must be allocated among the partners, such as partnership liabilities, data pertaining to the computation of the depletion allowance, and guaranteed payments. Treas. Reg. ss.301.6231(a)(3)-1. Generally, the IRS must conduct an administrative determination as to partnership items at the partnership level before conducting deficiency proceedings against a partner, and the partners must file a request for an administrative determination before filing suit for any credit or refund. The period for assessing tax against the Participants attributable to a partnership item generally may be extended by agreement between the IRS and the Managing General Partner, which will serve as each Partnership's representative ("Tax Matters Partner") in all administrative tax proceedings or tax litigation conducted at the partnership level. The Tax Matters Partner generally may enter into a settlement on behalf of, and binding on, any Participant owning less than a 1% profits interest in a Partnership if there are more than 100 partners in the Partnership, which, based on its past experience, the Managing General Partner anticipates will be the case for both Partnerships. By executing the Partnership Agreement, each Participant agrees that he will not form or exercise any right as a member of a notice group and will not file a statement notifying the IRS that the Tax Matters Partner does not have binding settlement authority. In addition, a partnership with at least 100 partners may elect to be governed under simplified tax reporting and audit rules as an "electing large partnership." I.R.C. ss.775. These rules would help the IRS match partnership items with the Participants' personal federal income tax returns. In addition, most limitations affecting the calculation of the taxable income and tax credits of an electing large partnership are generally applied at the partnership level and not the partner level. Thus, the Managing General Partner does not anticipate that either Partnership will make this election. All expenses of any proceedings involving the Managing General Partner as Tax Matters Partner, which might be substantial, will be paid for by the Partnership being audited. The Managing General Partner, however, is not obligated to contest adjustments made by the IRS. The Managing General Partner will notify the Participants of any IRS audits or other tax proceedings involving their Partnership, and will provide the Participants any other information regarding the proceedings as may be required by the Partnership Agreement or law. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 33 Tax Returns. A Participant's individual income tax returns are the responsibility of the Participant. Each Partnership will provide its Participants with the tax information applicable to their investment in the Partnership necessary to prepare their tax returns. Profit Motive, IRS Anti-Abuse Rule and Judicial Doctrines Limitations on Deductions. Under ss.183 of the Code, a Participant's ability to deduct his share of his Partnership's losses and possibly his ability to use his share of his Partnership's tax credits, if any, could be limited or lost if the Partnership lacks the appropriate profit motive as determined from an examination of all facts and circumstances at the time. Section 183 of the Code creates a presumption that an activity is engaged in for profit if, in any three of five consecutive taxable years, the gross income derived from the activity exceeds the deductions attributable to the activity. Thus, if a Partnership fails to show a profit in at least three out of five consecutive years this presumption will not be available and the possibility that the IRS could successfully challenge the Partnership deductions and tax credits, if any, claimed by its Participants would be substantially increased. The fact that the possibility of ultimately obtaining profits is uncertain, standing alone, does not appear to be sufficient grounds for the denial of losses or credits under ss.183 of the Code. (See Treas. Reg. ss.1.183-2(c), Example (5).) Under Treas. Reg. ss.1.701-2, if a principal purpose of a partnership is to reduce substantially the partners' federal income tax liability in a manner that is inconsistent with the intent of the partnership rules of the Code, based on all the facts and circumstances, the IRS is authorized to remedy the abuse. For illustration purposes, the following factors may indicate that a partnership is being used in a prohibited manner: o the partners' aggregate federal income tax liability is substantially less than had the partners owned the partnership's assets and conducted its activities directly; o the partners' aggregate federal income tax liability is substantially less than if purportedly separate transactions are treated as steps in a single transaction; o one or more partners are needed to achieve the claimed tax results and have a nominal interest in the partnership or are substantially protected against risk; o substantially all of the partners are related to each other; o income or gain are allocated to partners who are not expected to have any federal income tax liability; o the benefits and burdens of ownership of property nominally contributed to the partnership are retained in substantial part by the contributing party; and o the benefits and burdens of ownership of partnership property are in substantial part shifted to the distributee partners before or after the property is actually distributed to the distributee partners. We also have considered the possible application to each Partnership and its intended activities of the potentially relevant judicial doctrines summarized below. o Step Transactions. This doctrine provides that where a series of transactions would give one tax result if viewed independently, but a different tax result if viewed together, then the IRS may combine the separate transactions. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 34 o Business Purpose. This doctrine involves a determination of whether the taxpayer has a business purpose, other than tax avoidance, for engaging in the transaction, i.e. a "profit objective." o Economic Substance. This doctrine requires a determination of whether, from an objective viewpoint, a transaction is likely to produce economic benefits in addition to tax benefits. This test is met if there is a realistic potential for profit when the investment is made, in accordance with the standards applicable to the relevant industry, so that a reasonable businessman, using those standards, would make the investment. o Substance Over Form. This doctrine holds that the substance of the transaction, rather than the form in which it is cast, governs. It applies where the taxpayer seeks to characterize a transaction as one thing, rather than another thing which has different tax results. Under this doctrine, the transaction must have practical economical benefits other than the creation of income tax losses. o Sham Transactions. Under this doctrine, a transaction lacking economic substance may be ignored for tax purposes. Economic substance requires that there be business realities and tax-independent considerations, rather than just tax-avoidance features, i.e. the transaction must have a reasonable and objective possibility of providing a profit aside from tax benefits. Shams include, for example, transactions entered into solely to reduce taxes, which is not a profit motive because there is no intent to produce taxable income. In our opinion, the Partnerships will possess the requisite profit motive under ss.183 of the Code, and the IRS anti-abuse rule in Treas. Reg. ss.1.701-2 and the potentially relevant judicial doctrines summarized above will not have a material adverse effect on the tax consequences of an investment in a Partnership by a typical Participant as described in our opinions. These opinions are based in part on: o the results of the previous partnerships sponsored by the Managing General Partner as set forth in "Prior Activities" in the Prospectus; and o the Managing General Partner's representations, which include representations that: o each Partnership will be operated as described in the Prospectus (see "Management" and "Proposed Activities" in the Prospectus); and o the principal purpose of each Partnership is to locate, produce and market natural gas and oil on a profitable basis, apart from tax benefits, as described in the Prospectus. The Managing General Partner's representations are supported by the geological evaluations and the other information for the Partnerships' proposed drilling areas, and the specific Prospects proposed to be drilled by Atlas America Public #14-2005(A) L.P. included in Appendix A to the Prospectus. Also, the Managing General Partner has represented that Appendix A in the Prospectus will be supplemented or amended to cover a portion of the specific Prospects proposed to be drilled by Atlas America Public #14-2005(B) L.P. when Units in that Partnership are first offered to prospective Participants. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 35 Federal Interest and Tax Penalties. Taxpayers must pay tax and interest on underpayments of federal income taxes and the Code contains various penalties, including a penalty equal to 20% of the amount of a substantial understatement of federal income tax liability. An understatement occurs if the correct income tax, as finally determined, exceeds the income tax liability actually shown on the taxpayer's federal income tax return. An understatement on a non-corporate taxpayer's federal income tax return is substantial if it exceeds the greater of 10% of the correct tax, or $5,000. In the case of a corporation, other than an S corporation or a personal holding company, an understatement is substantial if it exceeds the lesser of: (i) 10% of the tax required to be shown on the return for the tax year (or, if greater, $10,000); or (ii) $10 million). I.R.C. ss.6662. A taxpayer may avoid this penalty if the understatement was not attributable to a "tax shelter," and there was substantial authority for the taxpayer's tax treatment of the item that caused the understatement, or if the relevant facts were adequately disclosed on the taxpayer's tax return and the taxpayer had a "reasonable basis" for the tax treatment of that item. In the case of an understatement that is attributable to a "tax shelter," however, which may include each of the Partnerships for this purpose, the penalty may be avoided only if there was reasonable cause for the underpayment and the taxpayer acted in good faith, or there is or was substantial authority for the taxpayer's treatment of the item, and the taxpayer reasonably believed that his or her treatment of the item on the tax return was more likely than not the proper treatment. For purposes of this penalty, the term "tax shelter" includes a partnership if a "significant" purpose of the partnership is the avoidance or evasion of federal income tax. In this regard, each Partnership anticipates incurring tax Losses during at least its first year when it pays (or prepays) the Participants' share of the costs of drilling its wells. Before the Code was amended in 1997, a partnership was defined as a tax shelter for purposes of ss.6662 of the Code if its "principal" purpose, rather than a "significant" purpose as the Code currently provides, was to avoid or evade federal income tax. Treas. Reg. ss.1.6662-4(g)(2)(ii), which has not been updated to reflect the 1997 amendment to ss.6662 discussed above, states: "The principal purpose of an entity, plan or arrangement is not to avoid or evade Federal income tax if the entity, plan or arrangement has as its purpose the claiming of exclusions from income, accelerated deductions or other tax benefits in a manner consistent with the statute and Congressional purpose. ..." As noted above, the 1997 amendment to ss.6662 of the Code changed the "principal" purpose to a "significant" purpose in the definition of a tax shelter for purposes of ss.6662. In our view, this amendment changed only the degree of the taxpayer's purpose (i.e. previously a principal purpose that exceeds any other purpose, as compared with the current requirement of only a significant purpose, which is one of two or more significant purposes). Accordingly, it would appear that neither Partnership should be treated as a "tax shelter" for purposes of ss.6662 of the Code if it incurs tax losses in accordance with standard commercial business practices as described in the Prospectus, and properly claims tax benefits under the Code, such as, for example, the deduction of Intangible Drilling Costs under ss.263(c) and Treas. Reg. ss.1.612-4(a); the deduction of ordinary, reasonable and necessary business expenses under ss.162 of the Code; and accelerated depreciation deductions on the Tangible Costs of its wells under ss.168 of the Code; in "a manner consistent with" the Code and Congressional purpose as set forth in Treas. Reg. ss.1.6662-4(g)(2)(ii). On the other hand, if a Partnership's tax treatment of its intended activities were to actually result in a substantial understatement of the correct amount of federal income taxes on its Participants' personal federal income tax returns, the IRS could argue, based on the facts and circumstances at that time, that the Partnership improperly claimed the tax benefits for the purpose of avoiding federal income taxes and should, therefore, be treated as a tax shelter for purposes of this penalty. Due to the many inherently factual determinations involved, we are unable to express an opinion on this issue. In addition, under ss.6662A of the Code there is a 20% penalty for reportable transaction understatements of federal income tax for any tax year. If the disclosure rules for reportable transactions are not met, then this penalty is increased from 20% to 30%, and the "reasonable cause" exception to the penalty, which is discussed below, will not be available. A reportable transaction understatement generally is the amount of the increase (if any) in taxable income resulting from the proper tax treatment of a tax item instead of the taxpayer's treatment of the tax item on the taxpayer's tax return, multiplied by the highest noncorporate income tax rate (or corporate income tax rate, in the case of a corporation). A tax item is subject to these rules if it is attributable to: o any listed transaction; and KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 36 o any other reportable transaction (other than a listed transaction) if a significant purpose of the transaction is federal income tax avoidance or evasion. The types of transactions which are reportable transactions under the Code are summarized below. In our opinion, based in part on the Partnerships' intended activities as described in the Prospectus and the Managing General Partner's representations, it is more likely than not that the Partnerships will not be treated as reportable transactions under ss.6707A of the Code and Treas. Reg. ss.1.6011-4(b). This opinion is based in part on the Managing General Partner's representation, which we believe is reasonable, that each Partnership's total abandonment losses under ss.165 of the Code, which could include, for example, the abandonment by a Partnership of wells drilled which are nonproductive (i.e. a "dry hole") or wells which have been operated until their commercial natural gas and oil reserves have been depleted (and each Participant's allocable share of those abandonment losses), will be less than $2 million in any taxable year and less than an aggregate total of $4 million during the Partnership's first six taxable years. The IRS, however, may at any time in its discretion publicly decide that a transaction which is the same as, or substantially similar to, the Partnerships is a "listed transaction," which is one type of reportable transaction summarized below. Being a reportable transaction would increase the risk that a Partnership's federal information income tax returns and the personal federal income tax returns of its Participants would be audited by the IRS. In this regard, however, merely being designated as a reportable transaction has no legal effect on whether the tax treatment of any transaction by a Partnership or its Participants for federal tax purposes was proper or improper. Also, as set forth above, even if a Partnership is a reportable transaction (other than a listed transaction), the penalty does not apply if the Partnership does not have a significant purpose to avoid or evade federal income taxes. See the discussion above concerning this issue. However, there might still be penalties against the material advisors to the Partnerships, including the Managing General Partner, Affiliates of the Managing General Partner, and third-parties, such as us, who have participated in creating, documenting, marketing or otherwise implementing this offering of Units in the Partnerships, whether or not there actually is a reportable transaction understatement of federal income tax. Under ss.6707A of the Code and Treas. Reg. ss.1.6011-4(b), there are six categories of reportable transactions, which are summarized below. (1) A listed transaction is the same as, or substantially similar to, a transaction that the IRS has publicly determined is a tax avoidance transaction. Because the determination of what additional transactions will be listed transactions is in the sole discretion of the IRS, there is always a possibility that the IRS could determine in the future that natural gas and oil drilling programs such as the Partnerships should be listed transactions, and therefore, must be treated as reportable transactions. (2) A confidential transaction includes an investment in which the investors' rights to disclose the tax treatment or tax structure of the investment are limited in order to protect the confidentiality of the tax strategies of the investment, and the person offering the investment is paid a fee of $50,000 or more by the investors for his or her tax services or strategies. The Partnerships are not confidential transactions, because they have no limitations on the disclosure of their tax treatment or tax structure. (3) A transaction with contractual protection generally is a transaction in which an investor has the right to a refund of a portion or all of his investment or any fees paid by him in connection with the transaction, if all or part of the intended tax consequences from the transaction ultimately are not sustained, or if a portion or all of his investment or any fees or other charges to be paid by the investor are contingent on the investor's realization of tax benefits from the transaction. In this regard, the Partnerships are not transactions with contractual protection, because no one, including the Managing General Partner, its Affiliates, or the Partnership, provides any contractual protection to the Participants against the possibility that part or all of the intended tax consequences or tax benefits of an investment in a Partnership by a Participant will be disallowed by the IRS. For example, the Managing General Partner, its Affiliates and the Partnerships provide no insurance, tax indemnity or similar agreement for the tax treatment of a Participant's investment in a Partnership, and a Participant has no right to rescind or receive a refund of any of the Participant's investment in the Partnership or any fees paid by the Partnership to the Managing General Partner, its Affiliates or independent third-parties, including us, if any intended tax consequences of the Participant's investment in a Partnership ultimately are not sustained if challenged by the IRS. None of these fees or payments is contingent on whether the intended tax consequences or tax benefits of a Partnership are ultimately sustained. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 37 (4) A loss transaction under Treas. Reg. ss.1.6011-4(b)(5), subject to certain exceptions, includes any investment resulting in a partnership or any non-corporate partner claiming a loss under ss.165 of the Code of at least $2 million in any single taxable year or $4 million in aggregate ss.165 losses in the taxable year that the investment is entered into and the five succeeding taxable years combined. For this purpose, a ss.165 loss includes an amount deductible under a provision of the Code that treats a transaction as a sale or other disposition, or otherwise results in a deduction under ss.165. A ss.165 loss includes, for example, a loss resulting from a sale or exchange of a partnership interest. The amount of a ss.165 loss is adjusted for any salvage value and for any insurance or other compensation received. However, a ss.165 loss for this purpose does not take into account offsetting gains, or other income limitations. In this regard, each Partnership anticipates incurring a tax Loss during at least its first year, due primarily to the amount of Intangible Drilling Costs it intends to claim as a deduction as described in the "Material Federal Income Tax Consequences - Summary Discussion of the Material Federal Income Tax Consequences of an Investment in a Partnership - Drilling Contracts" section of the Prospectus. The Managing General Partner anticipates that each Partnership's Loss in its first taxable year will be in an amount greater than $2 million, with the actual amount of the Loss of each Partnership depending primarily on the amount of the Partnership's subscription proceeds. In our opinion, however, it is more likely than not that Losses claimed by a Partnership which result from deductions claimed by the Partnership for Intangible Drilling Costs of productive wells (other than any remaining Intangible Drilling Costs of a well which is abandoned if a Participant has elected to amortize the Participant's share of the Intangible Drilling Costs of that well) should not be treated as ss.165 losses under the Code for purposes of the reportable transactions rules under the Code and the Treasury Regulations. In this regard, IRS Revenue Procedure 2003-24, 2003-11 C.B. 599, provides, in part, that certain losses under ss.165 of the Code are not taken into account in determining whether a transaction is a loss transaction under Treas. Reg. ss.1.6011-4(b)(5) as described above, including: "...A loss that is equal to, and is determined solely by the reference to, a payment of cash by the taxpayer (for example, a cash payment by a guarantor that results in a loss or a cash payment that is treated as a loss from the sale of a capital asset under ss.1234A or ss.1234B." This provision of the Revenue Procedure tends to support the position that a loss resulting from the deduction of Intangible Drilling Costs should not be treated as a loss under ss.165 of the Code for purposes of determining whether a Partnership is a reportable transaction. For example, it could be argued that the loss resulting from the deduction for Intangible Drilling Costs is a loss that is equal to, and determined solely by, the Partnership's cash payment of Intangible Drilling Costs to the Managing General Partner, acting as general drilling contractor. On the other hand, the examples of the excluded losses set forth in the language quoted above from the Revenue Procedure do not specifically include a loss resulting from a deduction of Intangible Drilling Costs as an example of an excluded loss. This may be because the deduction for Intangible Drilling Costs is not a deductible loss under ss.165 at all, but is deductible under ss.263(c) of the Code and Treas. Reg. ss.1.612-4(a), and therefore is irrelevant with respect to ss.165 of the Code, or it may be because the deduction of Intangible Drilling Costs is not intended by the IRS to be excluded from being a reportable transaction under the Revenue Procedure. This lack of substantial authority with respect to this issue creates some doubt as to the proper federal tax treatment of a Loss resulting from the deduction of Intangible Drilling Costs for purposes of determining whether a Partnership is a reportable transaction under Treas. Reg. ss.1.6011-4(b)(5). Therefore, our opinions expressed above with respect to these issues are "more likely than not" opinions. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 38 \ Also, if a Partnership drills a "dry hole" i.e. a well which is nonproductive, or plugs and abandons a productive well after its commercial natural gas and oil reserves have been produced and depleted, which in the case of the wells to be drilled by the Partnerships the Managing General Partner has represented is likely to be many years after the well was drilled, then the Partnership will abandon the well and claim a loss under ss.165 of the Code in the amount of its remaining basis in the well and perhaps the Prospect which includes the well. The Partnership's remaining basis in the abandoned well and Prospect may consist of, for example, leasehold acquisition expenses not previously recovered through the depletion allowance or the cost of unsalvageable equipment that has not previously been recovered through depreciation deductions. (See " - Lease Acquisition Costs and Abandonment," above.) The Intangible Drilling Costs of the well, however, would previously have been expensed by the Partnership, since the Managing General Partner has represented that each Partnership will make the election under ss.263(c) of the Code and Treas. Reg. ss.1.612-4(a) to expense, rather than capitalize, the Intangible Drilling Costs of all of its wells. In the case of a Participant, however, the abandonment loss may include the Participant's unamortized allocable share of the Partnership's Intangible Drilling Costs if the Participant elected to amortize those costs over 60 months. In this regard, however, the Managing General Partner has represented that it believes that each productive well drilled by a Partnership will produce for more than five years. Therefore, although possible, it is not likely that a Participant's share of the abandonment losses of the Partnership in which the Participant invests will include any portion of the Participant's share of the Partnership's Intangible Drilling Costs. Thus, the Managing General Partner has represented that although possible, it does not anticipate that either Partnership's abandonment loss claims under ss.165 of the Code for its dry holes, if any, or depleted wells, will ever total $2 million or more in losses in any single taxable year, or $4 million or more in total aggregate losses in the Partnership's first six years after the wells are drilled, which are the thresholds which would cause a Partnership to be a reportable transaction under Treas. Reg. ss.1.6011-4(b)(5) as described above. (5) A transaction which has a significant book-tax difference generally is a reportable transaction if the amount for tax purposes of any item or items of income, gain, expense, or loss from the investment differs by more than $10 million on a gross basis from the amount of the item or items for book purposes in any taxable year. This provision does not apply to Participants in the Partnerships who are natural persons, but does apply to taxpayers that are reporting companies under the Securities Exchange Act of 1934 which may include the Partnerships. In this regard, IRS Revenue Procedure 2003-25, 2003-11CB 601, provides, among other things, that book-tax differences arising from percentage depletion under ss.ss.613 or 613A of the Code; Intangible Drilling Costs deductible under ss.263(c) of the Code; and depreciation and amortization relating solely to differences in methods, useful lives or recovery periods, conventions, etc., are not taken into account in determining whether a transaction has a significant book-tax difference for this purpose. Thus, the Managing General Partner has represented that it does not anticipate that the Partnerships will have a significant book-tax difference for this purpose in any of their taxable years. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 39 (6) A transaction involving a brief asset holding period is any investment resulting in an investor claiming a tax credit exceeding $250,000 if the underlying asset giving rise to the credit is held by the taxpayer for 45 days or less. Under current tax laws this type of reportable transaction should not include the Partnerships, because no productive well of a Partnership which may generate marginal well production tax credits as discussed in "- Marginal Well Production Credits," above, will be held by the Partnership for 45 days or less. In addition, even if all of the Partnerships' wells were taken into account (which the Managing General Partner anticipates would be approximately 407 wells as set forth in the Prospectus), the Managing General Partner believes that any marginal well production credits arising from the natural gas and oil production for that short period of time would not exceed $250,000. The reportable transaction understatement penalty is not imposed if the taxpayer shows that there was a reasonable cause for the understatement and that the taxpayer acted in good faith. This exception generally does not apply to any reportable transaction understatement unless: o the tax treatment of the item is adequately disclosed to the IRS; o there is or was substantial authority for the tax treatment; and o the taxpayer reasonably believed that its tax treatment was more likely than not the proper treatment. Under ss.6664(d)(3)(B)(ii) of the Code, our tax opinion letter cannot be relied on by the Participants in either Partnership to establish their "reasonable belief" for purposes of this exception to the penalty, because we have been compensated directly by the Managing General Partner for providing this tax opinion letter and helping organize and document the offering. Therefore, if the situation ever arises, a Partnership's Participants must establish their "reasonable belief" for this purpose by some means other than this tax opinion letter. See " - Limitations on the Investors' Use of Our Tax Opinion Letter," above. Also, under ss.7525 of the Code, written communications with respect to tax shelters are not subject to the confidentiality provision that otherwise applies to communications between a taxpayer and a federally authorized tax practitioner, such as a certified public accountant. The term "tax shelter" for purposes of this rule, includes a partnership if it has a significant purpose of avoiding or evading income tax. In this regard, see the discussion of the substantial understatement of income tax penalty above. In addition, under ss.ss.6111 and 6112 of the Code, each material advisor, as defined below, (which may include the Managing General Partner and others, including us, if the Partnerships are a reportable transactions), must file a return with the IRS which identifies the reportable transaction and describes the potential tax benefits of the reportable transaction. Generally, a "material advisor" for purposes of reporting reportable transactions to the IRS and for other purposes under the Code is a person who provides any material aid in organizing, managing or selling a reportable transaction and who derives gross income for his services of $50,000 or more with respect to a reportable transaction in which substantially all of the tax benefits go to natural persons. No filing by the Participants in that Partnership would be required unless a Participant's allocable share of the Partnership's ss.165 losses separately met the dollar amount thresholds described above for a ss.165 loss transaction or the Partnership is a reportable transaction under one of the other types of reportable transactions. Also, in the first year of filing, a copy must be sent to the IRS's Office of Tax Shelter Analysis. Again, however, merely disclosing a reportable transaction to the IRS when required to do so (or as a precautionary measure, in the Managing General Partner's discretion, if the filing requirement is not clear) has no effect on the legal determination of whether any claimed tax position by a Partnership is proper or improper. Material advisors also must maintain a list that identifies each person with respect to whom the advisor acted as a material advisor for the reportable transaction (which may include the Participants in a Partnership if the Managing General Partner determines that either or both of the Partnerships is a reportable transaction or if the Partnership is ultimately found by the IRS or the courts to be a reportable transaction) and contains any other information concerning the transaction as may be required by the IRS. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 40 The penalty under ss.6707 of the Code for failing to disclose the reportable transaction generally is $50,000, but for a listed transaction it is generally the greater of $200,000 or 50% (75% if the failure was intentional) of the material advisor's gross income from the transaction. The penalty under ss.6708 of the Code for failing to maintain the required list and make the list available on written request by the IRS within 20 business days is $10,000 per day. State and Local Taxes. Each Partnership will operate in states and localities which impose a tax on it or its Participants based on its assets or its income. The Partnerships also may be subject to state income tax withholding requirements on their income or on their Participants' share of their income, whether their revenues that created the income are distributed to their Participants or not. Deductions and credits, including the federal marginal well production credit, which may be available to Participants for federal income tax purposes, may not be available for state or local income tax purposes. A Participant's share of the net income or net loss of the Partnership in which he invests generally must be included in determining the Participant's reportable income for state or local tax purposes in the jurisdiction in which he is a resident. To the extent that a non-resident Participant pays tax to a state because of Partnership operations within that state, he may be entitled to a deduction or credit against tax owed to his state of residence with respect to the same income. To the extent that the Partnership operates in certain jurisdictions, state or local estate or inheritance taxes may be payable on the death of a Participant in addition to taxes imposed by his own domicile. Prospective Participants are urged to seek advice based on their particular circumstances from an independent tax advisor to determine the effect state and local taxes, including gift and death taxes as well as income taxes, may have on them in connection with an investment in a Partnership. Severance and Ad Valorem (Real Estate) Taxes. Each Partnership may incur various ad valorem or severance taxes imposed by state or local taxing authorities on its natural gas and oil wells and/or natural gas and oil production from the wells. These taxes would reduce the amount of the Partnership's cash available for distribution to its Participants. Social Security Benefits and Self-Employment Tax. A Limited Partner's share of income or loss from a Partnership is excluded from the definition of "net earnings from self-employment." No increased benefits under the Social Security Act will be earned by Limited Partners and if any Limited Partners are currently receiving Social Security benefits, their shares of Partnership taxable income will not be taken into account in determining any reduction in benefits because of "excess earnings." An Investor General Partner's share of income or loss from a Partnership will constitute "net earnings from self-employment" for these purposes. I.R.C. ss.1402(a). The ceiling for social security tax of 12.4% in 2005 is $90,000. There is no ceiling for medicare tax of 2.9%. Self-employed individuals can deduct one-half of their self-employment tax. Farmouts. Under a Farmout by a Partnership, if a property interest, other than an interest in the drilling unit assigned to the Partnership Well in question, is earned by the farmee (anyone other than the Partnership) from the farmor (the Partnership) as a result of the farmee drilling or completing the well, then the farmee must recognize income equal to the fair market value of the outside interest earned, and the farmor must recognize gain or loss on a deemed sale equal to the difference between the fair market value of the outside interest and the farmor's tax basis in the outside interest. Neither the farmor nor the farmee would have received any cash to pay the tax. The Managing General Partner has represented that it will attempt to eliminate or reduce any gain to a Partnership from a Farmout, if any. However, if the IRS claims that a Farmout by a Partnership results in taxable income to the Partnership and its position is ultimately sustained, the Participants in that Partnership would be required to include their share of the resulting taxable income on their personal income tax returns, even though the Partnership and its Participants received no cash from the Farmout. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. December 27, 2004 Page 41 Foreign Partners. Each Partnership generally will be required to withhold and pay income tax to the IRS at the highest rate under the Code applicable to Partnership income allocable to its foreign Participants, even if no cash distributions are made to them. I.R.C. ss.1446. Also, a purchaser of a foreign Participant's Units may be required to withhold a portion of the purchase price and the Managing General Partner may be required to withhold with respect to taxable distributions of real property to a foreign Participant. These withholding requirements do not obviate United States tax return filing requirements for foreign Participants. In the event of overwithholding a foreign Participant must file a United States tax return to obtain a refund. Under ss.1441 of the Code, for withholding purposes a foreign Participant generally means a nonresident alien individual or a foreign corporation, partnership, trust or estate, if the Participant has not certified to his Partnership the Participant's nonforeign status. Foreign investors are urged to seek advice based on their particular circumstances from an independent tax advisor regarding the applicability of these rules and the other tax consequences of an investment in a Partnership to them. Estate and Gift Taxation. There is no federal tax on lifetime or testamentary transfers of property between spouses. The gift tax annual exclusion in 2005 is $11,000 per donee, which will be adjusted in subsequent years for inflation. Under the Economic Growth and Tax Relief Reconciliation Act of 2001 (the "2001 Tax Act"), the maximum estate and gift tax rate of 47% in 2005 will be reduced in stages to 46% in 2006 and 45% from 2007 through 2009. Estates of $1.5 million in 2005, which increases in stages to $2 million in 2006, 2007 and 2008, and $3.5 million in 2009, or less generally are not subject to federal estate tax. Under the 2001 Tax Act, the federal estate tax will be repealed in 2010, and the maximum gift tax rate in 2010 will be 35%. In 2011 the federal estate and gift taxes are scheduled to be reinstated under the rules in effect before the 2001 Tax Act was enacted. Changes in the Law. A Participant's investment in a Partnership may be affected by changes in the tax laws. For example, in 2003 the top four federal income tax brackets for individuals were reduced through December 31, 2010, including reducing the top bracket to 35% from 38.6%. The lower federal income tax rates will reduce to some degree the amount of taxes a Participant can save by virtue of his share of his Partnership's deductions for Intangible Drilling Costs, depletion and depreciation, and marginal well production credits, if any. On the other hand, the lower federal income tax rates also will reduce the amount of federal income tax liability incurred by a Participant on his share of the net income of his Partnership. There is no assurance that the federal income tax brackets discussed above will not be changed again before 2011. Prospective Participants are urged to seek advice based on their particular circumstances from an independent tax advisor with respect to the impact of recent legislation on an investment in a Partnership and the status of legislative, regulatory or administrative developments and proposals and their potential effect on them if they invest in a Partnership. We consent to the use of this tax opinion letter as an exhibit to the Registration Statement, and all amendments to the Registration Statement, including post-effective amendments, and to all references to this firm in the Prospectus. Very truly yours, /s/ Kunzman & Bollinger, Inc. KUNZMAN & BOLLINGER, INC.