EX-8 3 ex-8.txt EXHIBIT 8 EXHIBIT 8 OPINION OF KUNZMAN & BOLLINGER, INC. AS TO FEDERAL 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 February 22, 2006 Atlas Resources, Inc. 311 Rouser Road Moon Township, Pennsylvania 15108 RE: Atlas America Public #15-2005 Program - 2006 Tax Opinion Letter --------------------------------------------------------------- Gentlemen: DISCLOSURES AND LIMITATION ON THE PARTICIPANTS' USE OF THIS TAX OPINION LETTER. o THIS TAX OPINION LETTER WAS WRITTEN TO SUPPORT THE PROMOTION OR MARKETING OF UNITS IN THE PARTNERSHIPS TO POTENTIAL PARTICIPANTS, AND WE HAVE HELPED THE MANAGING GENERAL PARTNER ORGANIZE AND DOCUMENT THE OFFERING OF UNITS IN THE PARTNERSHIPS. o THIS TAX OPINION LETTER IS NOT CONFIDENTIAL. THERE ARE NO LIMITATIONS ON THE DISCLOSURE BY ANY POTENTIAL PARTICIPANT IN A PARTNERSHIP TO ANY OTHER PERSON OF THE TAX TREATMENT OR TAX STRUCTURE OF THE PARTNERSHIPS OR THE CONTENTS OF THIS TAX OPINION LETTER. o PARTICIPANTS IN A PARTNERSHIP HAVE NO CONTRACTUAL PROTECTION AGAINST THE POSSIBILITY THAT A PORTION OR ALL OF THEIR INTENDED TAX BENEFITS FROM AN INVESTMENT IN THE PARTNERSHIP ULTIMATELY ARE NOT SUSTAINED IF CHALLENGED BY THE IRS. (SEE "RISK FACTORS - TAX RISKS - YOUR TAX BENEFITS FROM AN INVESTMENT IN A PARTNERSHIP ARE NOT CONTRACTUALLY PROTECTED," IN THE PROSPECTUS.) o BECAUSE WE HAVE ENTERED INTO A COMPENSATION ARRANGEMENT WITH THE MANAGING GENERAL PARTNER AND WE HAVE PROVIDED THE LEGAL SERVICES TO THE PARTNERSHIPS DISCUSSED ABOVE, UNDER THE INTERNAL REVENUE CODE (THE "CODE") THIS TAX OPINION LETTER WAS NOT WRITTEN, AND CANNOT BE USED BY ANY PARTICIPANT IN A PARTNERSHIP, FOR THE PURPOSE OF ESTABLISHING THE PARTICIPANT'S REASONABLE BELIEF THAT HIS TAX TREATMENT OF ANY PARTNERSHIP TAX ITEM ON HIS INDIVIDUAL FEDERAL INCOME TAX RETURNS WAS MORE LIKELY THAN NOT THE PROPER TREATMENT IN ORDER TO AVOID ANY REPORTABLE TRANSACTION UNDERSTATEMENT PENALTY UNDER SS.6662A OF THE CODE. THUS, EACH POTENTIAL PARTICIPANT IN A PARTNERSHIP IS URGED TO SEEK ADVICE FROM AN INDEPENDENT TAX ADVISOR WITH RESPECT TO WHETHER AN INVESTMENT IN A PARTNERSHIP WOULD SUBJECT THE PARTICIPANT TO THAT PENALTY. o EACH POTENTIAL PARTICIPANT IN A PARTNERSHIP IS URGED TO SEEK ADVICE BASED ON HIS PARTICULAR CIRCUMSTANCES FROM AN INDEPENDENT TAX ADVISOR WITH RESPECT TO THE FEDERAL TAX CONSEQUENCES OF AN INVESTMENT IN A PARTNERSHIP. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 2 INTRODUCTION. Atlas America Public #15-2005 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 #15-2005(A) L.P., Atlas America Public #15-2006(B) L.P. and Atlas America Public #15-2006(C) L.P. (each a "Partnership" or all collectively the "Partnerships"). The offer and sale of Units in Atlas America Public #15-2005(A) L.P. closed on December 31, 2005, and Units in that Partnership are no longer being offered. Thus, the remaining unsold Units in the Program are being offered in 2006 by the Partnerships designated Atlas America Public #15-2006(___) L.P. Atlas Resources, Inc., the Managing General Partner of each Partnership, has requested our opinions on the material and any significant federal income tax issues pertaining to the purchase, ownership and disposition of Units in the Partnerships by potential "typical Participants," as that term is defined below in "- We Have Relied On Representations of the Managing General Partner for Purposes of Our Opinions." 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 DOCUMENTS WE HAVE REVIEWED AND EXISTING TAX LAWS. Our opinions and the "Summary Discussion of the Federal Income Tax Consequences of an Investment in a Partnership by a Typical Participant (the "Summary Discussion")" 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 filed with the SEC, as amended, which includes the Prospectus and the forms of Partnership Agreement and Drilling and Operating Agreement which are included as exhibits to the Prospectus; o other records, certificates, agreements, instruments and documents of the Managing General Partner and the Partnerships as we deemed relevant and necessary to review as a basis for our opinions; and 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 federal tax laws, which may take effect retroactively, may cause the actual tax consequences of an investment in a Partnership to vary substantially from those set forth in this tax opinion letter, and could render our opinions inapplicable. OUR OPINIONS ARE BASED IN PART ON ASSUMPTIONS WE HAVE MADE. 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 will not be borrowed from any other Participant in that Partnership or from a "related person," as that term is defined in ss.465 of the Code, to any other Participant in that Partnership. o If a Participant uses borrowed funds to purchase Units in a Partnership, the Participant will be severally, primarily, and personally liable for the borrowed amount. o No Participant will protect himself through nonrecourse financing, guarantees, stop loss agreements or other similar arrangements from losing the money he paid to a Partnership to purchase his Units. o The Partnership Agreement allocates each Partnership's income, gains, losses, deductions, and credits, or items thereof, including the allocations of basis and amount realized with respect to natural gas and oil properties, between the Managing General Partner and the Participants, and among the Participants as a group. Some of those tax items are allocated in different ratios than other tax items (i.e. special allocations). In order for those special allocations to be accepted by the IRS, the allocations must have substantial economic effect. Economic effect means that if there is an economic benefit or burden that corresponds to an allocation, the Participant to whom the allocation is made must receive the corresponding economic benefit or bear the corresponding economic burden. The economic effect of an allocation is substantial if there is a reasonable possibility that the allocation will affect substantially the dollar amounts to be received by the Participants from the Partnership in which they invest, independent of tax consequences and taking into account the Participants' tax attributes that are unrelated to the Partnership in which they invest. We, and the Managing General Partner, do not know the particular tax circumstances of any potential Participant in a Partnership which are unrelated to the Partnership in which the Participant invests. Therefore, for purposes of giving our opinion concerning the allocation provisions in the Partnership Agreement, we have assumed that taking into account the Participants' tax attributes that are unrelated to the Partnership in which they invest will not cause the economic effect (as defined above) of the allocation provisions in the Partnership Agreement to not be substantial (as defined above). See our opinion (11) in the "- Opinions" section of this tax opinion letter. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 3 WE HAVE RELIED ON 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, which are set forth below, which are 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.) 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 Assumptions We Have Made," 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. In relying on the Managing General Partner's representations set forth below and its statements in the Prospectus, we have taken into account the Managing General Partner's experience in natural gas and oil exploration, development and operations, including organizing and managing natural gas and oil drilling limited partnerships, and its knowledge of industry practices in the Appalachian Basin, as evidenced by "Prior Activities," "Management" and "Appendix A" in the Prospectus. The representations we have obtained from the Managing General Partner for purposes of giving our opinions, as discussed above, are set forth below. 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 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 Drilling and Operating Agreement, the Delaware Revised Uniform Limited Partnership Act, and any other applicable limited partnership act. 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 No Partnership will elect to be taxed as a corporation or elect out of the partnership provisions under Subchapter K of Chapter 1 of Subtitle A of the Code. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 4 o Each Partnership will own only Working Interests in all of its Prospects. o No Partnership's Units will be traded on an established securities market. o The Investor General Partner Units in each Partnership will be converted by the Managing General Partner to Limited Partner Units 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 and completed no more than 12 months after that Partnership's final closing, and the conversion in that Partnership will then follow. 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 The Managing General Partner anticipates that third-parties, as co-owners of the Working Interest in the wells, will participate with each Partnership in drilling some of that Partnership's wells, and those third-parties will not be required to prepay any of their share of the costs of drilling those 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, all of the Intangible Drilling Costs of all of its wells. o Based on information the Managing General Partner has concerning drilling rates of third-party drilling companies in the Appalachian Basin, the estimated costs of non-affiliated persons to drill and equip wells in the Appalachian Basin as reported for 2003 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 2003, the amounts that will be paid by each Partnership to the Managing General Partner or its Affiliates under the Drilling and Operating Agreement to drill and complete that Partnership's wells at Cost plus a nonaccountable, fixed payment reimbursement of $15,000 per well for the Participants' share of its general and administrative overhead 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 each Partnership's 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 a profit of 15% (approximately $32,803) per well, in addition to the nonaccountable, fixed payment reimbursement of $15,000 per well for its general and administrative overhead, 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 estimated weighted average allocation between Intangible Drilling Costs and Tangible Costs 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 each Partnership's wells as set forth in "Compensation - Drilling Contracts" in the Prospectus is reasonable. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 5 o The Managing General Partner anticipates that all of each Partnership's subscription proceeds will be expended in 2006, and the related income, if any, and deductions, including the deduction for Intangible Drilling Costs, will be reflected on its Participants' individual federal income tax returns for 2006, subject to each Participant's right to elect to capitalize and amortize over a 60-month period a portion or all of the Participant's share of the Partnership's deduction for Intangible Drilling Costs. o Each of the Partnerships designated Atlas America Public #15-2006(___) L.P. may have its final closing as late in the year as December 31, 2006. Thus, depending primarily on when its subscription proceeds are received, each Partnership may prepay in 2006 most, if not all, of its Intangible Drilling Costs for wells the drilling of which will not begin until 2007. o Each Partnership will attempt to comply with the guidelines set forth in Keller v. Commissioner with respect to prepaid Intangible Drilling Costs for any of its wells the drilling of which will not begin until 2007. 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, for purposes of the potentially: o higher rates of percentage depletion available under the Code; and o available marginal well production credits, depending primarily on the applicable reference prices for natural gas and oil, which may vary from year to year. o The Managing General Partner anticipates that the percentage depletion allowance for 2007 will be 15%. 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 in any year 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 anticipates that the amount of its amortization deductions for organization expenses related to the creation of each Partnership will not be material as compared to the total amount of 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 to its Participants, 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 #15-2006(C) L.P. if Units in that Partnership are offered to prospective Participants. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 6 o The Managing General Partner will not consent to any transfers of Units in any Partnership which would cause the Partnership to be considered 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 any 12-month period). o Based 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, further anticipates that none of the Partnerships will elect to be governed under simplified tax reporting and audit rules as an "electing large partnership," although they reserve the right to do so, because most limitations affecting the calculation of the taxable income and tax credits of an electing large partnership are applied at the partnership level and not the partner level. 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 each Partnership's Units, the Managing General Partner anticipates that the Partnerships will not make the ss.754 election, although they reserve the right to do so. 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. 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 Based primarily on the Managing General Partner's past experience (as shown in "Prior Activities" in the Prospectus), including Atlas America's 97% completion rate for wells drilled by its previous development drilling partnerships in the Appalachian Basin (see "- Management," in the Prospectus): o each Partnership's total abandonment losses under ss.165 of the Code, which could include, for example: o abandonment losses incurred by a Partnership for wells drilled which are nonproductive (i.e. a "dry hole"); or o abandonment losses incurred by a Partnership for productive wells which have been operated until their commercial natural gas and oil reserves have been depleted; will be less than $2 million, in the aggregate, in any taxable year of each Partnership, and less than $4 million, in the aggregate, during each Partnership's first six taxable years; o when a well is plugged and abandoned by a Partnership, the salvage value of the well's equipment usually will cover a substantial amount of the costs of abandoning and reclaiming the well site; o each Partnership will drill relatively few non-productive wells (i.e., "dry holes"), if any; KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 7 o each productive well drilled by a Partnership will have a different productive life and the wells will not all be depleted and abandoned in the same taxable year; o each productive well drilled by a Partnership will produce natural gas or oil for more than six years; and o approximately 617 gross wells, which is approximately 588.5 net wells, will be drilled by a Partnership if the maximum subscription proceeds of $147,726,000 are received by the Partnership (see "Terms of the Offering - Subscription to a Partnership," in the Prospectus), based on the Managing General Partner's estimate of the average weighted cost of drilling and completing a Partnership's wells (see "Compensation - Drilling Contracts," in the Prospectus). 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 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. Under Circular 230, 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; and a federal tax issue is significant if the IRS has a reasonable basis for a successful challenge and the resolution of the tax issue could have a significant impact, whether beneficial or adverse and under any reasonably foreseeable circumstance, on the overall federal tax treatment of a Partnership or a Participant's investment in a Partnership. We consider a federal tax issue to be material if its resolution: 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 attributable to his interest in his Partnership 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 federal tax issues, our opinions are only predictions, and are not guarantees, of the outcome of the particular federal 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 from an Investment in a Partnership 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 in a Partnership. Taxpayers bear the burden of proof to support claimed deductions and credits, and our opinions are not binding on the IRS or the courts. Our opinions 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. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 8 Our opinions with respect to the proper federal tax treatment of each federal tax issue arising from an investment in a Partnership by a typical Participant (who is sometimes referred to as a Limited Partner or an Investor General Partner in our opinions) are set forth below. (1) PARTNERSHIP CLASSIFICATION. Each Partnership will be classified as a partnership for federal income tax purposes, and not as a corporation. (See "- Partnership Classification" in the Summary Discussion section of this tax opinion letter.) (2) LIMITATIONS ON PASSIVE ACTIVITY LOSSES AND CREDITS. The passive activity limitations on losses and credits under ss.469 of the Code will apply to: o the initial Limited Partners in a Partnership; and o will not apply to the Investor General Partners in a Partnership until after their Investor General Partner Units are converted to Limited Partner Units in the Partnership. For a discussion of the passive activity limitations on losses and credits of natural persons who invest in a Partnership and the types of entities whose investments in a Partnership also will be subject to the passive activity limitations on losses and credits, see "- Limitations on Passive Activity Losses and Credits," in the Summary Discussion section of this tax opinion letter. (3) NOT A PUBLICLY TRADED PARTNERSHIP. No Partnership will be treated as a publicly traded partnership under the Code. (See " - Publicly Traded Partnership Rules" in the Summary Discussion section of this tax opinion letter.) (4) BUSINESS EXPENSES. 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 Offering Costs and other items which are required to be capitalized, are currently deductible. o POTENTIAL LIMITATIONS ON DEDUCTIONS. A Participant's ability in any taxable year to use his share of these Partnership deductions on his individual federal income tax returns may be reduced, eliminated or deferred by the following limitations: o the Participant's personal tax situation, such as the amount of his regular taxable income, alternative minimum taxable income, losses, itemized deductions, personal exemptions, etc., which are not related to his investment in a Partnership; KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 9 o the amount of the Participant's adjusted basis in his Units in the Partnership in which he invests at the end of the Partnership's taxable year; o the amount of the Participant's "at risk" amount in the Partnership in which he invests at the end of the Partnership's taxable year; and o the passive activity limitations on losses and credits in the case of Limited Partners (including Investor General Partners after their Investor General Partner Units are converted to Limited Partner Units) who are natural persons, or which are entities that also are subject to the passive activity limitations on losses and credits. See "- Limitations on Passive Activity Losses and Credits," "- Business Expenses," "- Tax Basis of Units," "- `At Risk' Limitation on Losses," and "- Alternative Minimum Tax" in the Summary Discussion section of this tax opinion letter. (5) INTANGIBLE DRILLING COSTS. Although each Partnership will elect to deduct currently all of its Intangible Drilling Costs, each Participant in a Partnership may still elect to capitalize and deduct all or part of his share of his Partnership's Intangible Drilling Costs (other than drilling and completion costs of a re-entry well that are not related to deepening the well, if any) ratably over a 60 month period 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 by Participants who elect to currently deduct their share of their Partnership's Intangible Drilling Costs in the taxable year in which the payments are made and the drilling services are rendered. (See "- Intangible Drilling Costs" in the Summary Discussion section of this tax opinion letter.) A Participant's ability in any taxable year to use his share of these Partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the "Potential Limitations on Deductions" set forth in opinion (4) above. (6) PREPAID INTANGIBLE DRILLING COSTS. Subject to each Participant's election to capitalize and amortize a portion or all of his share of his Partnership's Intangible Drilling Costs as set forth in opinion (5) above, any prepayments of Intangible Drilling Costs by a Partnership in 2006 for wells the drilling of which will begin after December 31, 2006, but on or before March 31, 2007, will be deductible by the Participants in that Partnership in 2006. (See "- Drilling Contracts" in the Summary Discussion section of this tax opinion letter.) A Participant's ability in any taxable year to use his share of these Partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the "Potential Limitations on Deductions" set forth in opinion (4) above. (7) DEPLETION ALLOWANCE. The greater of the cost depletion allowance or the percentage depletion allowance will be available to qualified Participants as a current deduction against their share of their Partnership's gross income from the sale of natural gas and oil production in each taxable year, subject to the following restrictions: KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 10 o a Participant's cost depletion allowance cannot exceed his adjusted tax basis in the natural gas or oil property to which it relates; and o a Participant's percentage depletion allowance: o may not exceed 100% of his taxable income from each natural gas and oil property before his deduction for percentage depletion; and o is limited to 65% of his taxable income for the year, computed without regard to percentage depletion, net operating loss carry-backs and capital loss carry-backs and, in the case of a Participant that is a trust, any distributions to its beneficiaries. See "- Depletion Allowance" in the Summary Discussion section of this tax opinion letter. (8) MACRS. Each Partnership's reasonable Tangible Costs for equipment placed in its productive wells which cannot be deducted immediately will be eligible for cost recovery deductions under the Modified Accelerated Cost Recovery System ("MACRS") over a seven year "cost recovery period" on a well-by-well basis, beginning in the taxable year each well is drilled, completed and made capable of production, i.e. placed in service. (See "- Depreciation and Cost Recovery Deductions" in the Summary Discussion section of this tax opinion letter.) A Participant's ability in any taxable year to use his share of these Partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the "Potential Limitations on Deductions" set forth in opinion (4), above. (9) TAX BASIS OF UNITS. Each Participant's initial adjusted tax basis in his Units in the Partnership in which he invests will be the amount of money that he paid for his Units. (See "- Tax Basis of Units" in the Summary Discussion section of this tax opinion letter.) (10) AT RISK LIMITATION ON LOSSES. Each Participant's initial "at risk" amount in the Partnership in which he invests will be the amount of money that he paid for his Units. (See "- `At Risk' Limitation on Losses" in the Summary Discussion section of this tax opinion letter.) (11) ALLOCATIONS. The allocations of income, gain, loss, deduction, and credit, or items thereof, and distributions set forth in the Partnership Agreement for each Partnership, including the allocations of basis and amount realized with respect to a Partnership's natural gas and oil properties, will govern each Participant's allocable share of those items to the extent the allocations do not cause or increase a deficit balance in his Capital Account in the Partnership in which he invests. (See "- Allocations" in the Summary Discussion section of this tax opinion letter.) (12) SUBSCRIPTION. No gain or loss will be recognized by the Participants on payment of their subscriptions to the Partnership in which they invest. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 11 (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 Participant as described in our opinions. (See "- Profit Motive, IRS Anti-Abuse Rule and Judicial Doctrines Limitations on Deductions" in the Summary Discussion section of this tax opinion letter.) (14) REPORTABLE TRANSACTIONS. The Partnerships are not, and should not be in the future, reportable transactions under ss.6707A(c) of the Code. However, because we have entered into a compensation arrangement with the Managing General Partner and has provided certain legal services to the Partnerships, under the Code this tax opinion letter was not written, and cannot be used by any Participant in a Partnership, for the purpose of establishing his reasonable belief that his tax treatment of any partnership tax item on his individual federal income tax returns was more likely than not the proper treatment in order to avoid any reportable transaction understatement penalty under ss.6662A of the Code. Thus, each potential Participant in a Partnership is urged to seek advice from an independent tax advisor with respect to whether an investment in a Partnership would subject the Participant to that penalty. (See "- Federal Interest and Tax Penalties" in the Summary Discussion section of this tax opinion letter.) (15) OVERALL CONCLUSION. Our overall conclusion is that the federal tax treatment of a typical Participant's investment in a Partnership as set forth in our opinions above is the proper federal tax treatment and will be upheld on the merits if challenged by the IRS and litigated. Our evaluation of the federal income tax laws and the expected activities of the Partnerships as represented to us by the Managing General Partner in this tax opinion letter and as described in the Prospectus causes us to believe that the deduction by a typical Participant of all, or substantially all, of his allocable share of his Partnership's Intangible Drilling Costs in 2006 (even if the drilling of most or all of his Partnership's wells begins after December 31, 2006, but on or before March 31, 2007, as set forth in opinions (5) and (6) above, is the principal tax benefit offered by each Partnership to its potential Participants and also is the proper federal tax treatment, subject to each Participant's election to capitalize and amortize a portion or all of his share of his Partnership's deduction for Intangible Drilling Costs as discussed in "- Alternative Minimum Tax" in the Summary Discussion section of this tax opinion letter. A Participant's ability in any taxable year to use his share of these Partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the "Potential Limitations on Deductions" set forth in opinion (4), above. The discussion in the Prospectus under the caption "FEDERAL INCOME TAX CONSEQUENCES," insofar as it contains statements of federal income tax law, is correct in all material respects. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 12 SUMMARY DISCUSSION OF THE FEDERAL INCOME TAX CONSEQUENCES OF AN INVESTMENT IN A PARTNERSHIP BY A TYPICAL PARTICIPANT (THE "SUMMARY DISCUSSION") INTRODUCTION. Our tax opinions are limited to those set forth above. The following is a summary discussion of all material federal income tax issues or consequences, and any significant federal tax issues, related to the purchase, ownership and disposition of a Partnership's Units which will apply to typical Participants in each Partnership. Except as otherwise noted below, however, different tax consequences from those discussed in this tax opinion letter may apply to Participants which are not natural persons or U.S. citizens, such as foreign persons, corporations, limited liability companies, partnerships and trusts, and other prospective Participants which 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 returns 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 his federal income tax liability. In addition, the IRS may challenge the deductions, and credits, if any, claimed by a Partnership or a Participant, or the taxable year in which the deductions, and credits, if any, are claimed, and it is possible that the challenge would be upheld if litigated. Accordingly, each prospective Participant is urged to seek advice based on his 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 alternative minimum tax preferences and adjustments from the partnership's operations on their individual federal income tax returns. A business entity with two or more members, such as the Partnerships 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 for federal tax purposes since the Managing General Partner has represented that neither of the Partnerships will elect to be taxed as a corporation. The Managing General Partner anticipates that all of the subscription proceeds of each Partnership will be expended in 2006, and the related income, if any, and deductions, including the deduction for Intangible Drilling Costs, will be reflected on its Participants' individual federal income tax returns for 2006, subject to each Participant's right to elect to capitalize and amortize over a 60-month period a portion or all of the Participant's share of the Partnership's deduction for Intangible Drilling Costs. (See "Capitalization and Source of Funds and Use of Proceeds" and "Participation in Costs and Revenues" in the Prospectus and "- Intangible Drilling Costs," "- Drilling Contracts," "- Depletion Allowance" and "- Depreciation and Cost Recovery Deductions," below.) LIMITATIONS ON PASSIVE ACTIVITY LOSSES AND CREDITS. 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. February 22, 2006 Page 13 The passive activity rules apply to: o individuals, estates, and trusts; o closely held C corporations which under ss.ss.469(j)(1), 465(a)(1)(B) and 542(a)(2) of the Code are regular corporations with five or fewer individuals who own directly or indirectly more than 50% in value of the outstanding stock at any time during the last half of the taxable year (for this purpose, U.S. trusts forming part of a stock bonus, pension or profit-sharing plan of an employer for the exclusive benefit of its employees or their beneficiaries which constitutes a "qualified trust" under ss.401(a) of the Code, trusts forming part of a plan providing for the payment of supplemental employee unemployment compensation benefits which meet the requirements of ss.501(c)(17) of the Code, domestic or foreign "private foundations" described in ss.501(c)(3) of the Code, and a portion of a trust permanently set aside or to be used exclusively for the charitable purposes described in ss.642(c) of the Code or a corresponding provision of a prior income tax law, are considered to be individuals); and o personal service corporations, which under ss.ss.469(j)(2), 269A(b) and 318(a)(2)(C) of the Code are corporations the principal activity of which is the performance of personal services and those services are substantially performed by employee-owners. For this purpose, the term "employee-owners" includes any employee who owns, on any day during the taxable year, any of the outstanding stock of the personal service corporation, and an employee is considered to own: o the employee's proportionate share of any stock of the personal service corporation owned, directly or indirectly, by or for a partnership or estate in which the employee is a partner or beneficiary; o the employee's proportionate share of any stock of the personal service corporation owned, directly or indirectly, by or for a trust (other than an employee's trust which is a qualified pension, profit-sharing, or stock bonus plan which is exempt from the tax) if the employee is a beneficiary; o all of the stock of the personal service corporation owned, directly or indirectly, by or for any portion of a trust of which the employee is considered the owner under the Code; and o if any stock in a corporation is owned, directly or indirectly, for or by the employee, the employee's portionate share of the stock of the personal service corporation owned, directly or indirectly, by or for that corporation. Provided, however, that a corporation will not be treated as a personal service corporation for purposes of ss.469 of the Code unless more than 10% of the stock (by value) in the corporation is held by employee-owners (as described above). I.R.C. ss.469(j)(2)(B). However, if a closely held C corporation, other than a personal service corporation in which employee-owners own more than 10% (by value) of the stock, has net active income (i.e., taxable income determined without regard to any income or loss from a passive activity and without regard to any item of portfolio income, expense (including interest expense), or gain or loss) for a taxable year, its passive loss for that taxable year can be applied against its net active income for that taxable year. Similar rules apply to its passive credits, if any. I.R.C. ss.469(e)(2). KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 14 Passive activities include any trade or business in which the taxpayer does not materially participate on a regular, continuous, and substantial basis. I.R.C. ss.469(c) and (h)(1) and (2). Under the Partnership Agreement, Limited Partners in a Partnership will not have material participation in the Partnership and will be subject to the passive activity limitations on losses and credits if they are included as taxpayers who are subject to ss.469 of the Code as described above. 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 from their Partnership 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 individual invests in a Partnership indirectly as an Investor General Partner by using an entity which limits his personal liability under state law to purchase his Units, such as, for example, a limited partnership in which he is not a general partner, a limited liability company or an S corporation, he will be subject to the passive activity limitations the same as a Limited Partner. As compared with limitations on liability under state law as discussed above, contractual limitations on the liability of Investor General Partners under the Partnership Agreement, such as insurance, limited indemnification by the Managing General Partner, etc. will not cause Investor General Partners to be subject to the passive activity limitations on losses and credits. Investor General Partners, however, may be subject to an additional limitation on their deduction of investment interest expense as a result of their non-passive deduction of Intangible Drilling Costs. (See "- Limitations on Deduction of Investment Interest," below.) A Limited Partner's "at risk" amount is reduced by losses allowed under ss.465 of the Code even if the losses are suspended by the passive activity limitations. (See "- `At Risk' Limitation on Losses," below.) Similarly, a Limited Partner's basis is reduced by deductions even if the deductions are suspended under the passive activity limitations. (See "- Tax Basis of Units," below.) Suspended passive losses and passive credits which cannot be used by a Participant in his current tax year may be carried forward indefinitely, but not back, and can be used to offset passive income in future years or, in the case of passive credits, can be used to offset regular federal income tax liability for passive income in future years. I.R.C. ss.469(b). A suspended passive loss, but not a suspended passive credit, is allowed in full when a taxpayer's entire interest in a passive activity is sold to an unrelated third-party in a fully taxable transaction, and in part on the taxable disposition of substantially all of a taxpayer's interest in a passive activity if the suspended passive loss as well as current gross income and deductions of the passive activity can be allocated to the part disposed of with reasonable certainty. I.R.C. ss.469(g)(1). In an installment sale of a taxpayer's entire interest in a passive activity, passive losses become available in the same ratio that gain recognized each year bears to the total gain on the sale. I.R.C. ss.469(g)(3). Any suspended passive losses remaining at a taxpayer's death are allowed as deductions on the decedent's final return, subject to a reduction to the extent that the amount of the suspended passive losses is greater than the excess of the basis of the property in the hands of the transferee over the property's adjusted basis immediately before the decedent's death. I.R.C. ss.469(g)(2). If a taxpayer makes a gift of his entire interest in a passive activity, the basis in the property of the person receiving the gift is increased by any suspended passive losses and no deductions are allowed. If the interest is later sold at a loss, the basis in the property of the person receiving the gift is limited to the fair market value on the date the gift was made. I.R.C. ss.469(j)(6). KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 15 PUBLICLY TRADED PARTNERSHIP RULES. Net losses and most net credits of a partner from a publicly traded partnership, including the marginal well production credit, are suspended and carried forward to be netted against income or regular federal income tax liability, respectively, from that publicly traded partnership only. (See "- Marginal Well Production Credits," below.) In addition, net passive 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 are readily tradable on either a secondary market or the substantial equivalent of a secondary market. However, in our opinion neither of the Partnerships will be treated as a publicly traded partnership under the Code. This opinion is based primarily on the substantial restrictions in the Partnership Agreement on each Participant's ability to transfer his Units. (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 the Partnerships' Units will not be traded on an established securities market. CONVERSION FROM INVESTOR GENERAL PARTNER TO LIMITED PARTNER. If a Participant invests in a Partnership as an Investor General Partner, then his share of that Partnership's deduction for Intangible Drilling Costs in 2006 will not be subject to the passive activity limitations on losses and credits. This is because the Managing General Partner has represented that the Investor General Partner Units in each Partnership will not be converted to Limited Partner Units by the Managing General Partner 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 each Partnership's productive wells will be drilled and completed no later than 12 months after the Partnership's final closing and the conversion will then follow. (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 limitations on losses and credits as a Limited Partner. However, the former Investor General Partner previously will have received a non-passive loss as an Investor General Partner in 2006 as a result of his Partnership's deduction for Intangible Drilling Costs. Therefore, the Code requires that his net income from the Partnership's wells after his conversion to a Limited Partner must continue to be characterized as non-passive income 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, if any, from his Partnership, see "- Marginal Well Production Credits," below. The conversion of the Investor General Partner Units into Limited Partner Units should not have any other adverse tax consequences on an Investor General Partner unless his share, if any, of any Partnership liabilities is reduced as a result of the conversion. Rev. Rul. 84-52, 1984-1 C.B. 157. This is because a reduction in a partner's share of liabilities is treated as a constructive distribution of cash to the partner, which reduces the partner's basis in his partnership units and is taxable to the partner the extent it exceeds his basis in his units. (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 the Partnership in which a Participant invests is important to the Participant because the Partnership's deductions, tax credits, if any, income and other items of tax significance must be taken into account on his personal federal income tax return for his taxable year within or with which his Partnership's taxable year ends. 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. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 16 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 federal income tax treatment of any prepaid Intangible Drilling Costs by the Partnerships.) BUSINESS EXPENSES. Ordinary, reasonable 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 that 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 payable by each Partnership to it or its Affiliates under the Partnership Agreement, and under the Drilling and Operating Agreement to drill and complete each Partnership's wells at Cost plus a nonaccountable, fixed payment reimbursement of $15,000 per well for the Participants' share of the Managing General Partner's general and administrative overhead 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 the 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 Lease acquisition costs or equipment costs ("Tangible Costs"); or o not "ordinary and necessary" business expenses. (See "- Depreciation and Cost Recovery Deductions" and "- Partnership Organization and Offering Costs," below.) In the event of an IRS 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. A Participant's ability in any taxable year to use his share of these Partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the "Potential Limitations on Deductions" set forth in opinion (4) of the "Opinions" section of this tax opinion letter. 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.) INTANGIBLE DRILLING COSTS. Each Participant may elect 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, in the taxable year in which the Partnership's wells are drilled and completed. I.R.C. ss.263(c), Treas. Reg. ss.1.612-4(a). For a discussion of the deduction of Intangible Drilling Costs that are prepaid by a Partnership in 2006 for wells the drilling of which will not begin until 2007, see "- Drilling Contracts," below. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 17 A Participant's deductions for his share of his Partnership's Intangible Drilling Costs (but not deductions for any operating expenses related to a re-entry well, if any, as discussed below) are subject to recapture as ordinary income, rather than capital gain, on the sale or other taxable disposition of the property by the Partnership or a Participant's Units by the Participant. (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, 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, such as Tangible Costs, Lease acquisition costs or syndication costs. However, this would have no effect on the allocation and payment of the Intangible Drilling Costs by the Participants under the Partnership Agreement. 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 and Lease acquisition costs, will be treated as Intangible Drilling Costs under the Code. The Intangible Drilling Costs of drilling and completing a re-entry well which are not related to deepening the well, if any, however, will be treated as operating expenses which should be expensed in the taxable year they are incurred for federal income tax purposes. Any Intangible Drilling Costs of a re-entry well which are treated as operating expenses for federal income tax purposes as described above, 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, and cannot be amortized as Intangible Drilling Costs over a 60-month period as described in "- Alternative Minimum Tax," below. (See "Participation in Costs and Revenues" in the Prospectus.) 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 average daily refinery runs in excess of 75,000 barrels for the taxable year. I.R.C. ss.291(b)(4). Amounts of an integrated oil company's Intangible Drilling Costs which are disallowed as a current deduction under ss.291 of the Code are allowable, however, as a deduction ratably over the 60-month period beginning with the month in which the costs are paid or incurred. The Partnerships will not be integrated oil companies. A Participant's ability in any taxable year to use his share of these Partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the "Potential Limitations on Deductions" set forth in opinion (4) in the "Opinions" section of this tax opinion letter above. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 18 Each Participant is urged to seek advice based on his particular circumstances from an independent tax advisor concerning the tax benefits to him of his share of the Partnership's deduction for Intangible Drilling Costs in the Partnership in which he invests. 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 at Cost plus a nonaccountable, fixed payment reimbursement of $15,000 per well for the Participants' share of the Managing General Partner's general and administrative overhead plus 15%. 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, its profit of 15% will be approximately $32,803 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 also could be more or less than the dollar amount estimated by the Managing General Partner as set forth above. 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 each Partnership may prepay in 2006 most, if not all, of its Intangible Drilling Costs for wells the drilling of which will begin in 2007. 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. February 22, 2006 Page 19 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 2006 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 for that Partnership, the drilling of which may begin in 2007. These prepayments of Intangible Drilling Costs should not result in a loss of a current deduction for the Intangible Drilling Costs in 2006 if: o the guidelines set forth in Keller are complied with; o there is a legitimate business purpose for the required prepayment; o the drilling of all of the prepaid wells begins on or before the close of the 90th day following the end of the taxable year in which the prepayment was made, i.e., March 31, 2007, as discussed below; 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. In this regard, 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. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 20 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. 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 the Drilling and Operating Agreement, the Managing General Partner, serving as operator and general drilling contractor, must begin drilling each Partnership's prepaid wells, if any, before the close of March 31, 2007, which is the 90th day after the close of each Partnership's taxable year in which the prepayment was made, which will be December 31, 2006. However, the drilling of any Partnership Well may be delayed due to circumstances beyond the control of the Managing General Partner and the drilling subcontractors. These circumstances include, for example: 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 (i.e., "force majeure") delay beginning the drilling of one or more of the prepaid wells, if any, past 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, 2007). 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, 2007), deductions claimed by a Participant in that Partnership for prepaid Intangible Drilling Costs for the well in 2006 would be disallowed and deferred to 2007 when the well is actually drilled. A Participant's ability in any taxable year to use his share of these Partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the "Potential Limitations on Deductions" set forth in opinion (4) in the "Opinions" section of this tax opinion letter above. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 21 DEPLETION ALLOWANCE. Proceeds from the sale of each Partnership's natural gas and oil production will constitute ordinary income. A portion of that income will not be taxable under the depletion allowance which permits the deduction from gross income for federal income tax purposes of either the percentage depletion allowance or the cost depletion allowance, whichever is greater. I.R.C. 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 by the Partnership or a Participant's Units by the Participant. (See "- Sale of the Properties" and "- Disposition of Units," below.) Cost depletion for any year is determined by dividing the adjusted tax basis for the property by the total units of natural gas or oil expected to be recoverable from the property and then multiplying the resultant quotient by the number of units actually sold during the year. Cost depletion cannot exceed the adjusted tax basis of the property to which it relates. Percentage depletion is available to taxpayers other than "integrated oil companies" as that term is defined in "- Intangible Drilling Costs," above, which does not include the Partnerships. Each Participant's percentage depletion allowance is based on the Participant's share of his Partnership's gross production income from its natural gas and oil properties. Under ss.613A(c) of the Code, percentage depletion is available with respect to 6 million cubic feet of average daily production of domestic natural gas or 1,000 barrels of average daily production of domestic crude oil. However, taxpayers who have both natural gas and oil production may allocate the production limitation between the production. 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. In this regard, 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 2006 is 15%, and it is also anticipated by the Managing General Partner to be 15% in 2007. 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 taxable income from each natural gas and oil property before the deduction for depletion, (this limitation was suspended in 2005 with respect to marginal properties, which the Managing General Partner has represented will include most, if not all, of each Partnership's wells, but as of the date of the Prospectus this limitation had not been suspended for 2006 and it may never be suspended for 2006 or subsequent taxable years (see I.R.C. ss.613A(c)(6)(H)); and (ii) is limited to 65% of the taxpayer's taxable income for the year computed without regard to percentage depletion, net operating loss carry-backs and capital loss carry-backs and, in the case of a Participant that is a trust, any distributions to its beneficiaries. Any percentage depletion deduction that is disallowed under this limitation may be carried forward to the following taxable year. I.R.C.ss.613A(d)(1). Availability of the percentage depletion allowance 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. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 22 DEPRECIATION AND COST RECOVERY DEDUCTIONS. Ten percent of each Partnership's subscription proceeds received from its Participants will be used to pay Tangible Costs and the Managing General Partner will pay all of the Partnership's remaining Tangible Costs of drilling and completing its wells. The related depreciation deductions of the Partnership, i.e., cost recovery deductions under the modified accelerated cost recovery system ("MACRS"), will be allocated under the Partnership Agreement between the Managing General Partner to the Participants in proportion to the actual amount of the Partnership's total Tangible Costs paid by each. A Partnership's reasonable Tangible Costs for equipment placed in its wells which cannot be deducted immediately will be recovered through depreciation deductions over a seven year cost recovery period using the 200% declining balance method, with a switch to straight-line to maximize the deduction, beginning in the taxable year each well is drilled, completed and made capable of production, i.e. placed in service by the Partnership. I.R.C. ss.168(c). In this regard, the Managing General Partner anticipates that each Partnership will have all of its wells drilled, completed and placed in service for the production of natural gas or oil approximately eight to 12 months after that Partnership's final closing. In the case of a short tax year of a Partnership, the MACRS deduction will be prorated on a 12-month basis. No distinction is made between new and used property and salvage value is disregarded. Under ss.168(d)(1) of the Code, all personal property assigned to the 7-year class is treated as placed in service, or disposed of, in the middle of the year unless the aggregate bases of all personal property placed in service in the last quarter of the year exceeds two-thirds of the aggregate bases of all personal property placed in service during the first nine months of the year. If that happens, under ss.168(d)(3) of the Code the mid-quarter convention will apply and the depreciation for the entire year will be multiplied by a fraction based on the quarter the personal property is placed in service: 87.5% for the first quarter, 62.5% for the second, 37.5% for the third, and 12.5% for the fourth. All cost recovery deductions claimed by each Partnership and its Participants are subject to recapture as ordinary income rather than capital gain on the sale or other taxable disposition of the property by the Partnership or a Participant's Units by the Participant. (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 will result in adjustments in computing the alternative minimum taxable income of the Participants in taxable years in which their Partnership claims depreciation deductions. (See "- Alternative Minimum Tax," below.) A Participant's ability in any taxable year to use his share of these Partnership deductions on his personal federal income tax returns may be reduced, eliminated or deferred by the "Potential Limitations on Deductions" set forth in opinion (4) in the "Opinions" section of this tax opinion letter above. MARGINAL WELL PRODUCTION CREDITS. Since 2005 the Code has provided 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 under current law this credit cannot be used against the alternative minimum tax. (See "- Alternative Minimum Tax," below.) However, the marginal well production credit is reduced proportionately if the reference prices for the previous calendar year are between $1.67 and $2.00 per mcf for natural gas and $15 and $18 per barrel for oil. In this regard, neither Partnership's natural gas and oil production in 2006, if any, will qualify for marginal well production credits in 2006, because the reference prices for natural gas and oil for 2005 will be substantially above the $2.00 per mcf of natural gas and $18.00 per barrel of oil prices where the credit phases out completely. Only holders of a Working Interest in a qualified well can claim the credit, which includes each Partnership and its Participants. Each Participant will share in his Partnership's marginal well production credits, if any, in the same proportion as his share of his Partnership's production revenues. (See "Participation in Costs and Revenues" in the Prospectus.) KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 23 The reference price for oil has not been under the $18.00 threshold necessary to qualify for any marginal well production credit for oil since 1999. More importantly, since the Managing General Partner anticipates that most of each Partnership's production from its wells will be natural gas, the average selling price after deducting all expenses, including transportation expenses, received by the Managing General Partner in each of its past four fiscal years for its natural gas production, has exceeded the $2.00 per mcf price needed to qualify for any marginal well production credits. (See "Proposed Activities - Sale of Natural Gas Production - Policy of Treating All Wells Equally in a Geographic Area," in the Prospectus.). Based on the current prices for natural gas and oil, compared with the prices at which the credit phases out completely, it may appear unlikely that either 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 a Partnership's production of natural gas or oil in one or more taxable years after 2006 could qualify for the marginal well production credit, depending primarily on the applicable reference prices for natural gas and oil in the future, since most, if not all, of each Partnership's natural gas and oil production will be qualified production for purposes of the credit as discussed below. However, depending primarily on market prices for natural gas and oil, which are volatile, a Partnership's production of natural gas and oil may not qualify for marginal well production credits for many years, if ever. Natural gas and oil production which qualifies as marginal production under the percentage depletion rules of ss.613A(c)(6) of the Code as discussed above in "- Depletion Allowance," 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. Thus, the natural gas and oil production from most, if not all, of each Partnership's wells will be potentially eligible for this credit, depending on the applicable reference price as discussed above. 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 the 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 the passive activity limitations in the case of Limited Partners. (See "- Limitations on Passive Activity Losses and Credits," above.) Under ss.469(c)(3) of the Code, an Investor General Partner's share of a 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, his share of his 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 the Partnership from the sale of its natural gas and oil production, which will still be 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 credits in excess of that amount which are allocable to the converted Investor General Partner, as well as all of the marginal well production credits allocable to those Participants who originally invested in a Partnership as Limited Partners, will be passive credits which under current law can reduce only the Participant's regular income tax liability attributable to net passive income from the Partnership or the Participant's other passive activities, if any, except publicly traded partnership passive activities. LEASE ACQUISITION COSTS AND ABANDONMENT. Lease acquisition costs, together with the related cost depletion deduction, any amortization deductions for geological and geophysical expenses incurred by the Managing General Partner after August 8, 2005, with respect o a Partnership's Prospects, and any abandonment loss for Lease acquisition costs, are allocated under the Partnership Agreement 100% to the Managing General Partner, which will contribute the Leases to each Partnership as a part of its Capital Contribution. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 24 TAX BASIS OF UNITS. A Participant's share of his Partnership's losses is allowable only to the extent of the adjusted basis of his Units at the end of the Partnership's taxable year. I.R.C. ss.704(d). The adjusted basis of the Participant's Units will be adjusted, but not below zero, for any gain or loss to the Participant from a sale or other taxable disposition by the Partnership of a natural gas and oil property, and will be increased by his: (i) cash subscription payment; (ii) share of Partnership income; and (iii) share, if any, of Partnership debt. The adjusted basis of a Participant's Units will be reduced by his: (i) share of Partnership losses; (ii) share of Partnership expenditures that are not deductible in computing its taxable income and are not properly chargeable to capital account; (iii) depletion deductions, but not below zero; (iv) cash distributions from the Partnership; and (v) any reduction in his share of his Partnership's debt, if any. I.R.C. ss.ss.705, 722 and 742. A reduction in a Participant's share of his Partnership's liabilities, if any, is considered to be a cash distribution from the Partnership 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 ON LOSSES. A Participant, other than a corporation which is neither an S corporation nor a corporation in which at any time during the last half of the taxable year five or fewer individuals owned more than 50% (in value) of the outstanding stock as set forth in ss.542(a)(2) of the Code, who sustains a loss in connection with his 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 the taxable year. I.R.C. ss.465. (See "- Limitations on Passive Activity Losses and Credits," above, relating to the application of ss.469 of the Code to closely held C corporations for additional information on the stock ownership requirements under ss.542(a)(2) of the Code. "Loss," for purposes of the "at risk" rules, means the excess of a Participant's share of the allowable deductions for a taxable year from his 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 in the Partnership in which he invests will be equal to the amount of money he paid 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 other Participant in his Partnership or from anyone related to another Participant in his Partnership. 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 the Partnership in which he invests will not include the amount of any loss that the Participant is protected against through: KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 25 o nonrecourse loans; o guarantees; o stop loss agreements; or o other similar arrangements. The amount of any loss that exceeds a Participant's "at risk" amount in the Partnership in which he invests at the end of any taxable year must be carried forward by the Participant to the next taxable year, and will then be available to the extent the Participant is "at risk" in the Partnership at the end of that taxable year. Further, a Participant's "at risk" amount in subsequent taxable years of the Partnership will be reduced by any portion of a Partnership loss which is allowable to the Participant as a deduction. Since income, gains, losses, and distributions of a Partnership will affect each Participant's "at risk" amount in the Partnership, the extent to which a Participant is "at risk" in the Partnership must be determined annually. Previously allowed losses must be included in gross income if a Participant's "at risk" amount is reduced below zero. The amount included in income, however, may be deducted in the next taxable year to the extent of any increase in the amount which the Participant has "at risk" in the Partnership. DISTRIBUTIONS FROM A PARTNERSHIP. 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). Different rules apply, however, in the case of payments by a Partnership to a deceased Participant's successor in interest under ss.736 of the Code and payments relating to unrealized receivables and inventory items under ss.751 of the Code. Under ss.731(a)(2) of the Code, no loss is recognized by the Participants on these types of distributions, unless the distribution is made in liquidation of the Participants' interests in their Partnership and only the property described below is distributed, and then only to the extent of the excess, if any, of the Participants' adjusted basis in their Units over the sum of: o the amount of money distributed to the Participants; plus o the Participants' share of basis (as determined under ss.732 of the Code) of any unrealized receivables (as defined in ss.751(c) of the Code) and inventory (as defined in ss.751(d) of the Code) of their Partnership. I.R.C. ss.731(a)(2). (See "- Disposition of Units," below, for a discussion of unrealized receivables and inventory items under ss.751 of the Code.) No gain or loss is recognized by a Partnership on cash distributions to its Participants. I.R.C. ss.731(b). If property is distributed by the Partnership to the Managing General Partner and the Participants, basis adjustments to the Partnership's properties may be made by the Partnership, and adjustments to their basis in their respective interests in the Partnership may be made by 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. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 26 SALE OF THE PROPERTIES. In 2003 the former maximum tax rates on a noncorporate taxpayer's adjusted net capital gain on the sale of most capital 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, were reduced to 15% and 5%, respectively, for most capital assets sold or exchanged after May 5, 2003. In addition, the former maximum tax rates of 18% and 8%, respectively, on qualified five-year gain were eliminated and, for 2008 only, the 5% tax rate on adjusted net capital gain was reduced to 0%. 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 they had never been changed. Under ss.1(h)(3) of the Code, "adjusted net capital gain" means net capital gain, determined without taking qualified dividend income into account, less any amount taken into account as investment income under ss.163(d)(4)(B)(iii) of the Code, and reduced (but not below zero) by net capital gain that is taxed a maximum rate of 28% (such as gain on the sale of most collectibles and gain on the sale of small business stock qualified under ss.1202 of the Code); or 25% (gain attributable to real estate depreciation); and increased by the amount of qualified dividend income. "Net capital gain" means the excess of net long-term capital gain (the excess of long-term gains over long-term losses) over net short-term capital loss (the excess of short-term gains over short-term losses). The annual capital loss limitation for noncorporate taxpayers is the amount of capital gains plus the lesser of $3,000, which is reduced to $1,500 for married persons filing separate returns, or the excess of capital losses over capital gains. I.R.C. ss.1211(b). Gain from the sale of the Partnerships' natural gas and oil properties held for more than 12 months will be treated as long-term capital gains, 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 non-recaptured ss.1231 losses (as defined below) for the five most recent preceding taxable years on previous sales, if any, of the Partnership's natural gas and oil properties or other assets. I.R.C. ss.1231(c). If, under ss.1231 of the Code, the ss.1231 gains for any taxable year exceed the ss.1231 losses for the taxable year, the gains and losses will be treated as long-term capital gains or long-term capital losses, as the case may be. If the ss.1231 gains do not exceed the ss.1231 losses, the gains and losses will not be treated as gains and losses from sales or exchanges of capital assets. For this purpose, the term "ss.1231 gain" means any recognized gain: o on the sale or exchange of property used in a trade or business; and o from the involuntary conversion into other property or money of: o property used in a trade or business; or o any capital asset which is held for more than one year and is held in connection with a trade or business or a transaction entered into for profit. The term "ss.1231 loss" means any recognized loss from a sale or exchange or conversion described above. The term "property used in a trade or business" means depreciable property and real property which are used in a trade or business and are held for more than one year, which are not inventory and are not held primarily for sale to customers in the ordinary course of a trade or business. Net ss.1231 gain will be treated as ordinary income to the extent the gain does not exceed the non-recaptured net ss.1231 losses. The term "non-recaptured net ss.1231 losses" means the excess of: o the aggregate amount of the net ss.1231 losses for the five most recent taxable years; over o the portion of those losses taken into account to determine whether the net ss.1231 gain for any taxable year should be treated as ordinary income to the extent the gain does not exceed the non-recaptured net ss.1231 losses, as discussed above, for those preceding taxable years. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 27 Other gains and losses on sales of natural gas and oil properties held by a Partnership for less than 12 months, if any, will result in ordinary gains or losses. In addition, deductions for Intangible Drilling Costs and depletion allowances that are incurred in connection with a natural gas or oil property may be recaptured as ordinary income when the property is sold or otherwise disposed of in a taxable transaction by a Partnership. The amount of gain recaptured as ordinary income is the lesser of: o the aggregate amount of expenditures which have been deducted as Intangible Drilling Costs with respect to the property and which, but for being deducted, would have been included in the adjusted basis of the property, plus deductions for depletion which reduced the adjusted basis of the property; or o the excess of: o the amount realized, in the case of a sale, exchange or involuntary conversion; or o the fair market value of the interest, in the case of any other taxable disposition; over the adjusted basis of the property. I.R.C. ss.1254(a). (See "- Intangible Drilling Costs" and "- Depletion Allowance," above.) Also, all gain on the sale or other taxable disposition of equipment by a Partnership will be treated as ordinary income to the extent of MACRS deductions claimed by the Partnership. I.R.C. ss. 1245(a). (See "- Depreciation and Cost Recovery Deductions," 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, if held by the Participant as a capital asset for more than 12 months, will result in the Participant's recognition of long-term capital gain or loss, except for the Participant's share of the Partnership's "ss.751 assets" (i.e. inventory items and unrealized receivables). All of these tax items may be recaptured as ordinary income rather than capital gain regardless of how long the Participant has owned his Units. "Unrealized receivables" includes any right to payment for goods delivered, or to be delivered, to the extent the proceeds would be treated as amounts received from the sale or exchange of non-capital assets; services rendered or to be rendered, to the extent not previously includable in income under the Partnerships' accounting methods; and the Participant's previous deductions for depreciation, depletion and Intangible Drilling Costs. I.R.C. ss.751(c)(1). "Inventory items" includes property properly includable in inventory and property held primarily for sale to customers in the ordinary course of business and any other property that would produce ordinary income if sold, including accounts receivable for goods and services. I.R.C. ss.ss.751(d) and 1221(a)(1). These tax items are sometimes referred to in this tax opinion letter as "ss.751 assets." (See "- Sale of the Properties," above.) If a Participant's Units are held for 12 months or less, the Participant's gain or loss 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 by the Participant. 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 sale or other taxable disposition of his Units. In addition to gain from a passive activity, a portion of any gain recognized by a Limited Partner on the sale or other taxable disposition of his Units will be characterized as portfolio income under ss.469 of the Code to the extent, if any, the gain is attributable to portfolio income, e.g. interest income on investments of his Partnership's working capital. Treas. Reg. ss.1.469-2T(e)(3). (See "- Limitations on Passive Activity Losses and Credits," above.) KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 28 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 types of dispositions of a Participant's Units may or may not result in recognition of taxable gain to the Participant. 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 ss.751 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 (i.e., ss.751 assets) allocable to the Units sold or exchanged (which is subject to recapture as ordinary income instead of capital gain as discussed above) and any other information as may be required by the IRS. The Partnership also must provide each person whose name is set forth in the return a written statement showing the information set forth on the return. If a Participant dies, 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 the death, sale or exchange, with a proration of partnership tax 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 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 sale or other disposition of their Units, including any purchase of the Units 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 is taxable income, plus or minus various adjustments, plus tax preference items. An "adjustment" means a substitution of alternative minimum tax treatment of a tax item in place of the regular tax treatment of that tax item. A "preference" means the addition of the difference between the alternative minimum tax treatment of a tax item and the regular tax treatment of that tax item. A "tax item" is any item of income, gain, loss, deduction or credit. The tax rate for noncorporate taxpayers is 26% for the first $175,000, $87,500 for married individuals filing separately, of a taxpayer's alternative minimum taxable income in excess of the exemption amount; and additional alternative minimum taxable income is taxed at 28%. However, the regular tax rates on capital gains also will apply for purposes of the alternative minimum tax. (See "- Sale of the Properties," above.) Subject to the phase-out provisions summarized below, the exemption amounts currently scheduled for 2006 are $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 2006 and subsequent years. For 2005, these exemption amounts were $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. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 29 The exemption amounts set forth above for 2006 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 $45,000 exemption amount is completely phased out when alternative minimum taxable income is $330,000 or more, and the $58,000 exemption amount in 2005 phased out completely at $382,000; o $112,500, in the case of unmarried individuals other than surviving spouses - the $33,750 exemption amount is completely phased out when alternative minimum taxable income is $247,500 or more, and the $40,250 exemption amount in 2005 phased out completely at $273,500; and o $75,000, in the case of married individuals filing a separate return - the $22,500 exemption amount is completely phased out when alternative minimum taxable income is $165,000 or more and the $29,000 exemption amount in 2005 phased out completely at $191,000. In addition, the alternative minimum taxable income of married individuals filing separately is increased for 2006 by the lesser of $22,500 ($29,000 for 2005) or 25% of the excess of the person's alternative minimum taxable income (determined without regard to this provision) over $165,000 ($191,000 for 2005). As of the date of the Prospectus, the higher exemption amounts for 2005 had not been extended to 2006. You are urged to seek advice from an independent tax advisor to determine whether the 2006 exemption amounts for 2006 alternative minimum tax purposes have been increased after the date of the Prospectus. 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 placed in service in the wells ("Tangible Costs") may not exceed deductions computed using the 150% declining balance method. These adjustments are discussed in greater detail below. (See "- Depreciation and Cost Recovery Deductions," above.) 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, which are itemized and deducted for regular tax purposes, are not deductible (in 2005 taxpayers could elect to itemize deductions for state and local sales taxes, instead of state and local income taxes for regular federal income tax purposes, but as of the date of the Prospectus, this election had not been extended to 2006, thus, you are urged to seek advice from an independent tax advisor to determine whether this deduction was subsequently extended to 2006). o Interest deductions are restricted. o The standard deduction and personal exemptions are not allowed. o Only some types of operating losses are deductible. o Passive activity losses are computed differently. o Earlier recognition of income from incentive stock options may be required. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 30 The principal tax preference items that must be added to taxable income for alternative minimum tax purposes include: o excess Intangible Drilling Costs, as discussed below; and o tax-exempt interest earned on specified private activity bonds less any deduction that would have been allowable if the interest were includible in gross income for regular income tax purposes. For this purpose, "specified private activity bond" means any private activity bond which is issued after August 7, 1986, and the interest on which is not includible in gross income under ss.103 of the Code, excluding any qualified ss.501(c)(3) bond (as defined in ss.145 of the Code). Also, a "private activity bond" does not include any refunding bond issued before August 8, 1986. 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 (except Intangible Drilling Costs of a re-entry well which are treated for tax purposes as operating costs, if any) and deduct the costs ratably over a 60-month period beginning with the month in which the costs were paid or incurred by the Partnership. This election also applies for regular tax purposes and can be revoked only with the IRS' consent. Making this election, therefore, will include the following principal consequences to the Participant: o the Participant's regular federal income tax deduction for Intangible Drilling Costs in 2006 will be reduced because he 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 his alternative minimum taxable income. Other than Intangible Drilling Costs as discussed above, and passive activity losses and credits in the case of Limited Partners, the principal tax item that may have an impact on a Participant's alternative minimum taxable income as a result of investing in a Partnership is depreciation of the Partnership's equipment expenses. (See "- Limitation on Passive Activity Losses and Credits," above.) As noted in "- Depreciation and Cost Recovery Deductions," above, each Partnership's cost recovery deductions for regular income tax purposes will be computed differently than for alternative minimum tax purposes. Consequently, in the early years of the cost recovery period of a Partnership's equipment, a Participant's depreciation deductions from the Partnership in which he invests will be smaller for alternative minimum tax purposes than the Participant's depreciation deductions for regular income tax purposes on the KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 31 same equipment. This, in turn, could cause a Participant to incur, or may increase, the Participant's alternative minimum tax liability in those taxable years. Conversely, the Participant will have larger depreciation deductions for alternative minimum tax purposes than for regular income tax purposes in the later years of the cost recovery period. Also, under current law 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. (See "- Marginal Well Production Credits," above.) In addition, the rules relating to the alternative minimum tax for corporations are different from those for individuals which have been 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 to subsequent taxable years. I.R.C. ss.163(d). 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. I.R.C. ss.163(d)(5)(A)(ii). In addition, an Investor General Partner's share of the Partnership's loss in 2006 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 2006, with the disallowed portion to be carried forward to the next taxable year. This limitation on the deduction of investment interest expenses, however, will not apply to any income or expenses taken into account by Limited Partners in computing their income or loss from the Partnership as a passive activity under ss.469 of the Code in the case of Limited Partners. I.R.C. ss.163(d)(4)(D). (See "- Limitations on Passive Activity Losses and Credits," above.) 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 some tax items are made in ratios that are different from allocations of other tax items. (See "Participation in Costs and Revenues" in the Prospectus.) The Capital Account of each Participant in a Partnership 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. Also, the basis of the natural gas and oil properties owned by a Partnership for purposes of computing cost depletion and gain or loss on disposition of a property will be allocated and reallocated when necessary in the ratio in which the expenditure giving rise to the tax basis of each property was charged as of the end of the year. (See ss.5.03(b) of the Partnership Agreement.) 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 Partnership income and gain to him; and decreased by: o the value of property or cash distributed to him by the Partnership; and o allocations of Partnership losses and deductions to him. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 32 The Treasury Regulations also require that there must be a reasonable possibility that a special allocation will affect substantially the dollar amounts to be received by the partners from the partnership, independent of tax consequences. For purposes of giving our tax opinions with respect to an investment in a Partnership, we have assumed that this requirement will be satisfied as explained in the "- Our Opinions Are Based In Part On Assumptions We Have Made" section of this tax opinion letter. An allocation will have economic effect if throughout the term of a partnership: o the partners' capital accounts are increased and decreased as described above; 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 by making additional Capital Contributions to their Partnership, an allocation which is not attributable to nonrecourse debt or tax credits will still be considered to have economic effect under the Treasury Regulations to the extent it does not cause or increase a deficit balance in a Participant's Capital Account if: o the Partners' Capital Accounts are increased and decreased as described above; o liquidation proceeds are distributed in accordance with the Partners' Capital Accounts; and o the Partnership Agreement provides that a Participant who unexpectedly incurs a deficit balance in his Capital Account because of adjustments, allocations, or distributions will be allocated Partnership 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 of the Treasury Regulations apply to deductions which are related to nonrecourse debt and tax credits, since allocations of these items cannot have substantial economic effect under the Treasury Regulations. 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 and "Participation in Costs and Revenues," in the Prospectus, and "- Marginal Well Production Credits," above.) 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 will be allocated among its Participants according to their varying interests in the Partnership during the taxable year. In addition, the Code may require Partnership property to be revalued on the admission of additional Participants, if disproportionate distributions are made to the Participants, or if there are "built-in" losses on the transfer of a Participant's Units or the distribution of a Partnership's property to its Participants. (See "- Tax Elections," below, for a discussion of these potential adjustments to a Partnership's properties.) KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 33 It should also be noted that each Participant's share of his Partnership's items of income, gain, loss, deduction and credit 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 that 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 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 of those tax items by the IRS, Participants may incur a greater tax burden. PARTNERSHIP BORROWINGS. Under the Partnership Agreement, only the Managing General Partner and its Affiliates may make loans to each Partnership, not to exceed at any one time an amount equal to 5% of the Partnership's subscription proceeds. The use of a Partnership's revenues taxable to its Participants to repay borrowings by the Partnership, however, 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 by the IRS as Capital Contributions to the Partnership by the Managing General Partner or its Affiliates in light of all of the surrounding facts and circumstances. For example, 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. Also, because the Participants do not bear the risk of repaying these borrowings with non-Partnership assets, the borrowings will not increase the extent to which the Participants are allowed to deduct their individual share of Partnership losses. 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, expense 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. I.R.C. ss.709; Treas. Reg. ss.ss.1.709-1 and 2. Although 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 Costs. Thus, any related deductions, which the Managing General Partner does not anticipate will be material in amount as compared to the total amount of subscription proceeds of each Partnership, will be allocated to the Managing General Partner. 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). If the ss.754 election is made, the transferees of the Units are treated, for purposes of depreciation and gain, as though they had acquired a direct interest in the Partnership assets and the Partnership is treated for these purposes, on distributions to the 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. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 34 In this regard, the Managing General Partner anticipates 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 properties when Units are sold, taking into account the limitations on the sale of each Partnership's Units, the Partnerships will not make the ss.754 election, although they reserve the right to do so. Even if the Partnerships do not make the ss.754 election, however, the basis adjustment described above is mandatory under the Code with respect to the transferee Partner only, if at the time a Unit is transferred by sale or exchange, or on the death of a Participant, the Partnership's adjusted basis in its properties exceeds the fair market value of the properties 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 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. In this regard, under ss.7.02(c) of the Partnership Agreement a Partnership will not distribute its assets in-kind to its Participants, except to a liquidating trust or similar entity for the benefit of its Participants, unless at the time of the distribution the Participants have been offered the election of receiving in-kind property distributions, and any Participant accepts the offer after being advised of the risks associated with direct ownership; or there are alternative arrangements in place which assure the Participants that they will not, at any time, be responsible for the operation or disposition of the Partnership's properties. 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 will not make in-kind property distributions to their respective Participants except in the limited circumstances described above, 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 reduce the likelihood that a Partnership will be required to make mandatory basis adjustments to its properties. In addition to the ss.754 election discussed above, each Partnership may make various elections under the Code for federal tax reporting purposes which could result in the deductions of intangible drilling costs and depreciation, and the depletion allowance, being treated differently for tax purposes than for accounting purposes. Also, 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 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, if paid or incurred in connection with the operation of an existing active trade or business in the same field, would be allowable as a deduction for the taxable year in which paid or incurred. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 35 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, and its Participants' share, if any, of those deductions, would be amortized over the 180-month period. TAX RETURNS AND IRS AUDITS. The tax treatment of most "partnership items," as that term is defined below, is determined at the Partnership, rather than the Partner, level. Accordingly, the Participants are required to treat partnership items of the Partnership in which they invest 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 returns unless they disclose to the IRS, by attaching IRS Form 8082 "Notice of Inconsistent Treatment or Administrative Adjustment Request (AAR)" to their individual federal income tax returns, that their tax treatment of partnership items on their personal federal income tax returns is different from their Partnership's tax treatment of those partnership items. 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. In most cases, the IRS must make an administrative determination as to partnership items at the Partnership level before conducting deficiency proceedings against a Partnership's Participants, and the Participants must file a request for an IRS administrative determination with respect to their Partnership before individually filing suit for any credit or refund. Also, the period for assessing tax against the Participants because of a partnership item 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 involving a Partnership. The Tax Matters Partner may enter into a binding settlement agreement on behalf of any Participant owning less than a 1% profits interest in a Partnership if there are more than 100 Partners in the Partnership, unless that Participant timely files a statement with the Secretary of the Treasury providing that the Tax Matters Partner does not have the authority to enter into a settlement agreement on behalf of that Participant. Based on its past experience, the Managing General Partner anticipates that there will be more than 100 Partners in each Partnership in which Units are offered for sale. However, by executing the Subscription Agreement each Participant also is executing the Partnership Agreement if his Subscription Agreement is accepted by the Managing General Partner, and under 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. However, most limitations affecting the calculation of the taxable income and tax credits of an electing large partnership are applied at the partnership level and not the partner level. Thus, the Managing General Partner does not anticipate that the Partnerships will make this election, although they reserve the right to do so. All expenses of any tax proceedings involving a Partnership and the Managing General Partner acting as Tax Matters Partner, which might be substantial, will be paid for by the Partnership and not by the Managing General Partner from its own funds. The Managing General Partner, however, is not obligated to contest any adjustments made by the IRS to a Partnership's federal information income tax returns, even if the adjustment also would affect the individual federal income tax returns of its Participants. 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. 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. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 36 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 deductions could be limited or lost if the Partnership lacks the appropriate profit motive as determined from an examination of all facts and circumstances at the time. Section 183 of the Code creates a presumption that an activity is engaged in for profit if, in any three of five consecutive taxable years, the gross income derived from the activity exceeds the deductions attributable to the activity. Thus, if a Partnership fails to show a profit in at least three out of five consecutive years this presumption will not be available and the possibility that the IRS could successfully challenge the Partnership deductions claimed by its Participants would be substantially increased. The fact that the possibility of ultimately obtaining profits is uncertain, standing alone, does not appear to be sufficient grounds for the denial of losses under ss.183 of the Code. (See Treas. Reg. ss.1.183-2(c), Example (5).) Also, if a principal purpose of a partnership is to reduce substantially the partners' federal income tax liability in a manner that is inconsistent with the intent of the partnership rules of the Code, based on all the facts and circumstances, the IRS is authorized to remedy the abuse. Treas. Reg. ss.1.701-2. 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; and o income or gain are allocated to partners who are not expected to have any federal income tax liability. In addition, we have considered the possible application to each Partnership and its intended activities of potentially relevant judicial doctrines which, if the IRS or a court found to be applicable to a Partnership, could substantially reduce or even eliminate the tax benefits of an investment in a Partnership by a Participant, including each Partnership's deduction for Intangible Drilling Costs in 2006. These doctrines are summarized below. o Step Transactions. This doctrine provides that where a series of transactions would give one tax result if viewed independently, but a different tax result if viewed together, then the IRS may combine the separate transactions. o Business Purpose. This doctrine involves a determination of whether the taxpayer has a business purpose, other than tax avoidance, for engaging in the transaction, i.e. a "profit objective." o Economic Substance. This doctrine requires a determination of whether, from an objective viewpoint, a transaction is likely to produce economic benefits in addition to tax benefits. Under the general rule, 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. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 37 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, under current law 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 to its Participants, apart from tax benefits, as described in the Prospectus. The Managing General Partner's representations also are supported by the information in "Proposed Activities" in the Prospectus concerning the Partnerships' proposed drilling areas, and by the geological evaluations and other information relating to the specific Prospects proposed to be drilled by Atlas America Public #15-2006(B) L.P. included in Appendix A to the Prospectus, which represent a portion of the wells to be drilled by that Partnership if its targeted maximum subscription proceeds of $125 million (which is not binding on the Partnership) are received as described in "Terms of the Offering - Subscription to a Partnership" in 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 #15-2006(C) L.P. if Units in that Partnership are offered to prospective Participants. FEDERAL INTEREST AND TAX PENALTIES. Taxpayers must pay tax and interest on underpayments of federal income taxes and the Code contains various penalties, including penalties for negligence and substantial property valuation misstatements with respect to their individual federal income tax returns. In addition, there is a penalty equal to 20% of the amount of a substantial understatement of federal income tax liability. There is a substantial understatement by a noncorporate taxpayer if the correct tax as finally determined by the IRS or the courts exceeds the income tax shown on the taxpayer's federal income tax return by the greater of 10% of the correct tax, or $5,000. In the case of a corporation, other than an S corporation or a personal holding company, as defined in ss.542 of the Code, an understatement is substantial if it exceeds the lesser of: (i) 10% of the correct tax (or, if greater, $10,000); or (ii) $10 million). I.R.C. ss.6662. A noncorporate taxpayer may avoid this penalty if the understatement was not attributable to a "tax shelter," as that term is defined below, and there is or was substantial authority for the taxpayer's tax treatment of the item that caused the understatement, or if the relevant facts were adequately disclosed on the taxpayer's individual federal income tax return or a statement attached to the return and the taxpayer had a "reasonable basis" for the tax treatment of that item. I.R.C. ss.6662(d)(2)(B). 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 (I.R.C. ss.6664(c)), or there is or was substantial authority for the taxpayer's tax treatment of the item that caused the understatement, and the taxpayer reasonably believed that his tax treatment of the item on his individual federal income tax return was more likely than not the proper treatment. I.R.C. 6664(d). KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 38 For purposes of this penalty, the term "tax shelter" includes a partnership if a "significant" purpose of the partnership is the avoidance or evasion of federal income tax. Because the IRS has not explained what a "significant" purpose of avoiding or evading federal income tax means, we cannot express an opinion as to whether the Partnerships are "tax shelters" as defined by the Code for purposes of this penalty. Also, under ss.6662A of the Code there is a 20% penalty for reportable transaction understatements of federal income taxes on a taxpayer's individual federal income tax return for any year. However, if the disclosure rules for reportable transactions under the Code and the Treasury Regulations are not met by the taxpayer, this penalty is increased from 20% to 30%, and a "reasonable cause" exception to the penalty which is set forth in the Code will not be available to the taxpayer. Under Treasury Regulation ss.1.6011-4, a taxpayer who participates in a reportable transaction in any taxable year must attach to his individual federal income tax return IRS Form 8886 "Reportable Transaction Disclosure Statement," and file it with the IRS as directed in the Regulation, in order to comply with the disclosure rules. A tax item is subject to the reportable transaction understatement rules if the tax item is attributable to: o any listed transaction, which is a transaction that is the same as, or substantially similar to, a transaction that the IRS has publicly pronounced to be a tax avoidance transaction; or o any of four additional types of reportable transactions, if a significant purpose of the transaction is federal income tax avoidance or evasion. As set forth above, we cannot express an opinion with respect to whether or not each Partnership has a "significant" purpose of federal income tax avoidance, because the IRS has not explained what that phrase means for purposes of this penalty. In our opinion, however, the Partnerships are not reportable transactions under ss.6707A(c) of the Code. However, because we have entered into a compensation arrangement with the Managing General Partner and have provided certain legal services to the Partnerships, under ss.6664(d)(3) of the Code this tax opinion letter was not written, and cannot be used by any Participant in a Partnership, for the purpose of establishing the Participant's reasonable belief that his tax treatment of any partnership tax item on his individual federal income tax returns was more likely than not the proper treatment in order to avoid any reportable transaction understatement penalty under ss.6662A of the Code. Thus, each potential Participant in a Partnership is urged to seek advice from an independent tax advisor with respect to whether an investment in a Partnership would subject the Participant to that penalty. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 39 Of the five types of reportable transactions under ss.6707A of the Code and Treas. Reg. ss.1.6011- 4(b), a "loss transaction" appears to us to be most likely to apply to the Partnerships, but only if it is assumed that the Partnerships have the "significant" purpose of federal income tax avoidance or evasion, which we believe is unclear under current legal authorities as discussed above. A "loss transaction" under Treas. Reg. ss.1.6011- 4(b)(5) includes any investment resulting in a partnership which has noncorporate partners, or resulting in any of the partnership's noncorporate partners, claiming a loss under ss.165 of the Code of at least $2 million, in the aggregate, in any single taxable year of the Partnership, or at least $4 million, in aggregate ss.165 losses, during the taxable year that the investment is entered into and the five succeeding taxable years combined. For purposes of the "loss transaction" rules, a ss.165 loss includes an amount deductible under a provision of the Code that treats a transaction as a sale or other disposition of property, or otherwise results in a deduction under ss.165. A ss.165 loss includes, for example, a loss resulting from a sale or exchange of a partnership interest, such as a Participant's Units in a Partnership. 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 under the Code. Each Partnership will incur a tax loss in 2006 in excess of $2 million, in the aggregate, if subscription proceeds of approximately $2,225,000 or more are received by the Partnership, or a loss in excess of $4 million, in the aggregate, in 2006 if subscription proceeds of approximately $4,450,000 or more are received by the Partnership, due primarily to the amount of Intangible Drilling Costs for productive wells that each Partnership intends to claim as a deduction. Notwithstanding the foregoing, in our opinion a Partnership's losses which result from deductions claimed for Intangible Drilling Costs for productive wells should be treated as losses under ss.263(c) of the Code and Treas. Reg. ss.1.612-4(a), and should not be treated as ss.165 losses for purposes of the "loss transaction" rules under Treas. Reg. 1.6011- 4(b)(5). However, each of the Partnerships may incur losses under ss.165 of the Code, such as losses for the abandonment by a Partnership of: o wells drilled which are nonproductive (i.e. a "dry hole"), if any, in which case the Intangible Drilling Costs, the Tangible Costs, and possibly the Lease acquisition costs of the abandoned wells would be deducted as ss.165 losses; and o productive wells which have been operated until their commercial natural gas and oil reserves have been depleted, in which case the undepreciated Tangible Costs, if any, and possibly the Lease acquisition costs, would be deducted as ss.165 losses. In this regard, based primarily on its past experience (as shown in "Prior Activities" in the Prospectus), including Atlas America's 97% completion rate for wells drilled by its previous development drilling partnerships in the Appalachian Basin (see "- Management," in the Prospectus), the Managing General Partner has represented the following: o when a well is plugged and abandoned by a Partnership, the salvage value of the well's equipment usually will cover a substantial amount of the costs of abandoning and reclaiming the well site; o each Partnership will drill relatively few non-productive wells (i.e., "dry holes"), if any; o each productive well drilled by a Partnership will have a different productive life and the wells will not all be depleted and abandoned in the same taxable year; o each productive well drilled by a Partnership will produce natural gas or oil for more than six years; o approximately 617 gross wells, which is approximately 588.5 net wells, will be drilled by a Partnership if the maximum subscription proceeds of $147,726,000 are received by the Partnership (see "Terms of the Offering - Subscription to a Partnership," in the Prospectus), based on the Managing General Partner's estimate of the average weighted cost of drilling and completing a Partnership's wells (see "Compensation - Drilling Contracts," in the Prospectus); and o each Partnership's total abandonment losses under ss.165 of the Code, as described above, will be less than $2 million, in the aggregate, in any taxable year of each Partnership, and less than $4 million, in the aggregate, during each Partnership's first six taxable years. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 40 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. Each Partnership also may be subject to state income tax withholding requirements on its income, or on its Participants' share of its income, whether or not the Partnership revenues that created the income are distributed to its Participants. Deductions and credits, including federal marginal well production credits, if any, which may be available to Participants for federal income tax purposes, may not be available to Participants for state or local income tax purposes. If a Participant resides in a state or locality that imposes income taxes on its residents, the Participant likely will be required under those income tax laws to include his share of his Partnership's net income or net loss in determining his reportable income for state or local tax purposes in the jurisdiction in which he resides. To the extent that a non-resident Participant pays tax to another 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. Also, due to a Partnership's operations in a state or local jurisdiction, 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. Each Partnership's Units may be sold in all 50 states and the District of Columbia, and it is not practical for us to evaluate the many different state and local tax laws that may affect one or more of a Partnership's Participants with respect to their investment in the Partnership. Thus, 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 will reduce the amount of each 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 2006 is $94,200. 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 individual income tax returns, even though the Partnership and its Participants received no cash from the Farmout. KUNZMAN & BOLLINGER, INC. Atlas Resources, Inc. February 22, 2006 Page 41 FOREIGN PARTNERS. Each Partnership 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. This withholding requirement does not obviate United States tax return filing requirements for foreign Participants. In the event of overwithholding, a foreign Participant must seek a refund on his individual United States income tax return. For Partnership withholding purposes, a foreign Participant means a Participant who is not a United States person within the meaning of ss.7701(a)(30) of the Code, and includes a nonresident alien individual, a foreign corporation, a foreign partnership, and a foreign trust or estate. However, a Participant will not be a foreign Participant if the Participant has certified to the Partnership in which he invests his status as a U.S. person on a valid IRS Form W-9 "Request for Taxpayer Identification Number and Certification," or any other form that is permitted under the Code and the Treasury Regulations to be used by the Partnerships to determine whether or not their Participants are foreign Participants. 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 amount is $12,000 per donee in 2006, 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 46% in 2006 will be reduced to 45% from 2007 through 2009. Estates of $2.0 million or less in 2006, which increases to $3.5 million or less in 2009, are not subject to federal estate tax to the extent those exemption amounts (i.e., unified credit amounts) were not previously used, in whole or in part, by the decedent to reduce federal gift taxes on any lifetime gifts in excess of the applicable annual exclusion amount for gifts. 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, however, 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 tax benefits from an 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 his Partnership's net income. However, the federal income tax brackets discussed above could be changed again, even before 2011, and other changes in the tax laws could be made that would affect a Participant's tax benefits from an investment in a Partnership. Each prospective Participant is urged to seek advice based on his particular circumstances from an independent tax advisor with respect to the impact of recent federal tax legislation on an investment in a Partnership and the status of federal and state legislative, regulatory or administrative tax developments and tax proposals and their potential effect on the tax consequences to him of an investment 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.