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
April 7, 2006
Atlas Resources, LLC
311 Rouser Road
Moon Township, Pennsylvania 15108
RE: Atlas America Public #15-2005 Program - 2006 Tax Opinion Letter
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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 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.
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, LLC, 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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 2
OUR OPINIONS ARE BASED IN PART ON DOCUMENTS WE HAVE REVIEWED AND
EXISTING TAX LAWS. Our opinions and the "Discussion of Federal Income Tax
Consequences" 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, LLC
April 7, 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.
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 4
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.
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 5
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.
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 6
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"); and
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;
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).
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 7
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.
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 8
(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 "Discussion of
Federal Income Tax Consequences" 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 "Discussion of Federal Income Tax
Consequences" 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 "Discussion
of Federal Income Tax Consequences" 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;
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 9
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
"Discussion of Federal Income Tax Consequences" 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," in the
"Discussion of Federal Income Tax Consequences" section of
this tax opinion letter. 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 "Discussion of
Federal Income Tax Consequences" 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 "Discussion of Federal
Income Tax Consequences" 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:
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:
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 10
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 "Discussion of Federal
Income Tax Consequences" 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
"Discussion of Federal Income Tax Consequences" 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 "Discussion of Federal
Income Tax Consequences" 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 "Discussion of
Federal Income Tax Consequences" 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 "Discussion of Federal Income Tax
Consequences" 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, LLC
April 7, 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 "Discussion of
Federal Income Tax Consequences" 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.
(See "- Federal Interest and Tax Penalties" in the "Discussion
of Federal Income Tax Consequences" 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
"Discussion of Federal Income Tax Consequences" 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.
DISCUSSION OF FEDERAL INCOME TAX CONSEQUENCES
INTRODUCTION. Our tax opinions are limited to those set forth above.
The following is a 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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 12
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 each Partnership, 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.)
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
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 13
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).
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.)
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 14
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).
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 15
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.
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.)
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 16
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.
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.)
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 17
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.
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 18
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.
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 19
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.
Under the Drilling and Operating Agreement excess prepaid Intangible
Drilling Costs, if any, will not be refundable to a Partnership, but instead
will be applied only to Intangible Drilling Cost overruns, if any, on the other
specified wells being drilled or completed by the Partnership or to Intangible
Drilling Costs to be incurred by the Partnership in drilling and completing
substitute wells. Under Keller, a provision for substitute wells should not
result in the prepayments being characterized as refundable deposits.
The likelihood that prepayments of Intangible Drilling Costs will be
challenged by the IRS on the grounds that there is no business purpose for the
prepayments is increased if prepayments are not required with respect to 100% of
the Working Interest in the well. In this regard, the Managing General Partner
anticipates that less than 100% of the Working Interest will be acquired by each
Partnership in one or more of its wells, and prepayments of Intangible Drilling
Costs will not be required of the other owners of Working Interests in those
wells. In our view, however, a legitimate business purpose for the required
prepayments of Intangible Drilling Costs by the Partnerships may exist under the
guidelines set forth in Keller, even though prepayments are not required by the
drilling contractor with respect to a portion of the Working Interest in the
wells.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 20
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.
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 21
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.
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 22
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.
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.)
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 23
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 to 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.
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 24
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:
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 25
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.
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).
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 26
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.
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:
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 27
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.)
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 28
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.
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
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 29
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.
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 30
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
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 31
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 carry forward 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.
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
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 32
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.)
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 33
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.
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 34
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.
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 35
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.
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).)
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 36
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.
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 37
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. Treasury
Regulation ss.1.6662-4(g).
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 38
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 ss.6664(d) of 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.
A "loss transaction" is one type of reportable transaction, but only 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, as discussed below.
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
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 39
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.
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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 40
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.
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 estates of $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.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, LLC
April 7, 2006
Page 41
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.