EXHIBIT 8
OPINION OF
KUNZMAN & BOLLINGER, INC.
AS TO
TAX MATTERS
KUNZMAN & BOLLINGER, INC.
ATTORNEYS-AT-LAW
5100 N. BROOKLINE, SUITE 600
OKLAHOMA CITY, OKLAHOMA 73112
Telephone (405) 942-3501
Fax (405) 942-3527
Exhibit 8
February 18, 2005
Atlas Resources, Inc.
311 Rouser Road
Moon Township, Pennsylvania 15108
RE: Atlas America Public #14-2004 Program - 2005 Tax Opinion Letter
Gentlemen:
DISCLOSURES AND LIMITATION ON INVESTORS' USE OF OUR TAX OPINION LETTER.
o ATLAS RESOURCES, INC., AS MANAGING GENERAL PARTNER OF EACH
PARTNERSHIP, HAS RETAINED US, KUNZMAN & BOLLINGER, INC., AS
SPECIAL COUNSEL TO ASSIST IN THE ORGANIZATION AND DOCUMENTATION
OF ITS PUBLIC OFFERING OF UNITS IN THE PARTNERSHIPS AND TO
PROVIDE THIS TAX OPINION LETTER TO SUPPORT THE MARKETING OF
UNITS IN THE PARTNERSHIPS TO POTENTIAL PARTICIPANTS. OUR
COMPENSATION ARRANGEMENT WITH THE MANAGING GENERAL PARTNER IS
NOT REFUNDABLE OR CONTINGENT ON ALL OR ANY PART OF THE INTENDED
TAX CONSEQUENCES OF AN INVESTMENT IN A PARTNERSHIP ULTIMATELY
BEING SUSTAINED IF CHALLENGED BY THE IRS OR ON THE PARTICIPANTS'
REALIZATION OF ANY TAX BENEFITS FROM THE PARTNERSHIP IN WHICH
THEY INVEST. ALSO, WE HAVE NO COMPENSATION OR REFERRAL
ARRANGEMENT WITH ANY PERSON OTHER THAN THE MANAGING GENERAL
PARTNER IN CONNECTION WITH THE OFFERING OF THE UNITS, AND WE
HAVE NO FEE-SHARING ARRANGEMENT WITH ANYONE IN CONNECTION WITH
THE OFFERING OF THE UNITS.
o BECAUSE WE HAVE ENTERED INTO A COMPENSATION ARRANGEMENT WITH THE
MANAGING GENERAL PARTNER TO PROVIDE THE LEGAL SERVICES TO THE
PARTNERSHIPS DISCUSSED ABOVE, THIS TAX OPINION LETTER WAS NOT
WRITTEN, AND CANNOT BE USED BY THE PARTICIPANTS, FOR THE PURPOSE
OF ESTABLISHING THEIR REASONABLE BELIEF THAT THEIR TAX TREATMENT
OF ANY PARTNERSHIP TAX ITEM ON THEIR FEDERAL INCOME TAX RETURNS
WAS MORE LIKELY THAN NOT THE PROPER TREATMENT IN ORDER TO AVOID
ANY REPORTABLE TRANSACTION UNDERSTATEMENT PENALTY UNDER
SECTION 6662A OF THE INTERNAL REVENUE CODE (THE "CODE") THAT MAY
BE IMPOSED ON THEM.
o THIS TAX OPINION LETTER IS NOT CONFIDENTIAL. THERE ARE NO
LIMITATIONS ON THE DISCLOSURE BY THE PARTNERSHIPS OR ANY
POTENTIAL PARTICIPANT TO ANY OTHER PERSON OF THE TAX TREATMENT
OR TAX STRUCTURE OF THE PARTNERSHIPS OR THE CONTENTS OF THIS TAX
OPINION LETTER.
o PARTICIPANTS HAVE NO CONTRACTUAL PROTECTION AGAINST THE
POSSIBILITY THAT A PORTION OR ALL OF THEIR INTENDED TAX BENEFITS
FROM AN INVESTMENT IN A PARTNERSHIP ULTIMATELY ARE NOT SUSTAINED
IF CHALLENGED BY THE IRS. (SEE "RISK FACTORS - TAX RISKS - YOUR
TAX BENEFITS
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Atlas Resources, Inc.
February 18, 2005
Page 2
ARE NOT CONTRACTUALLY PROTECTED," IN THE PROSPECTUS AND "-
FEDERAL INTEREST AND TAX PENALTIES," BELOW.)
o POTENTIAL PARTICIPANTS ARE URGED TO SEEK ADVICE BASED ON THEIR
PARTICULAR CIRCUMSTANCES FROM AN INDEPENDENT TAX ADVISOR WITH
RESPECT TO THE FEDERAL TAX ISSUES OF AN INVESTMENT IN A
PARTNERSHIP.
THE LIMITATION SET FORTH ABOVE ON THE PARTICIPANTS' USE OF THIS TAX OPINION
LETTER WITH RESPECT TO THE REPORTABLE TRANSACTION UNDERSTATEMENT PENALTY APPLIES
ONLY FOR FEDERAL TAX PURPOSES. IT DOES NOT APPLY TO THE PARTICIPANTS' RIGHT TO
RELY ON THIS TAX OPINION LETTER AND THE DISCUSSION IN THE "MATERIAL FEDERAL
INCOME TAX CONSEQUENCES" SECTION OF THE PROSPECTUS UNDER THE FEDERAL SECURITIES
LAWS.
INTRODUCTION. Atlas America Public #14-2004 Program (the "Program"), is
a series of up to three natural gas and oil drilling limited partnerships, all
of which have been formed under the Delaware Revised Uniform Limited Partnership
Act. The limited partnerships are Atlas America Public #14-2004 L.P., Atlas
America Public #14-2005(A) L.P., and Atlas America Public #14-2005(B) L.P. Atlas
America Public #14-2004 L.P. had its final closing on November 15, 2004. Atlas
Resources, Inc. is the Managing General Partner of all of the limited
partnerships. Since the offering of Units in Atlas America Public #14-2004 L.P.
has closed, the Managing General Partner has requested our opinions on the
material or significant federal income tax issues pertaining to the purchase,
ownership and disposition of Units in Atlas America Public #14-2005(A) L.P. and
Atlas America Public #14-2005(B) L.P. (each a "Partnership" or both collectively
the "Partnerships") by potential Participants. Capitalized terms used and not
otherwise defined in this tax opinion letter have the respective meanings
assigned to them in the form of Amended and Restated Certificate and Agreement
of Limited Partnership for the Partnerships (the "Partnership Agreement"), which
is included as Exhibit (A) to the Prospectus.
OUR OPINIONS ARE BASED IN PART ON DOCUMENTS WE HAVE REVIEWED AND
EXISTING TAX LAWS. Our opinions and the "Summary Discussion of the Material
Federal Income Tax Consequences and Any Significant Federal Tax Issues of an
Investment in a Partnership (the "Summary Discussion")" section of this tax
opinion letter are based in part on our review of:
o the current Registration Statement on Form S-1 for the
Partnerships, as amended, filed with the SEC, including the
Prospectus, the Partnership Agreement and the form of Drilling
and Operating Agreement included as exhibits in the Prospectus;
o other records, certificates, agreements, instruments and
documents as we deemed relevant and necessary to review as a
basis for our opinions; and
o current provisions of the Code, existing, temporary and proposed
Treasury Regulations, the legislative history of the Code,
existing IRS administrative rulings and practices, and judicial
decisions. Future changes in existing law, which may take effect
retroactively, may cause the actual tax consequences of an
investment in the Partnerships to vary substantially from those
set forth in this letter, and could render our opinions
inapplicable.
OUR OPINIONS ARE BASED IN PART ON ASSUMPTIONS WE HAVE MADE. For purposes
of our opinions, we have made the assumptions set forth below.
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Atlas Resources, Inc.
February 18, 2005
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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 a "related person," as that term is
defined in Section 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 for
his Units.
o The drilling of all of each Partnership's specified wells and
substitute wells, if any, for which Intangible Drilling Costs
were prepaid in 2005, actually begins on or before March 31,
2006, and the wells are drilled continuously until completed, if
warranted, or abandoned.
o The Partnership Agreement allocates a Partnership's income,
gain, loss, deduction, and credit, 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 economic benefit or bear the
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
Participant 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), below in the "Opinions" section of this
tax opinion letter.
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, in
addition to statements made by the Partnerships and the Managing General Partner
in the Prospectus concerning the Partnerships and their proposed activities,
including forward-looking statements. (See "Forward-Looking Statements and
Associated Risks" in the Prospectus.) We have found the Managing General
Partner's representations and the statements in the Prospectus to be reasonable
and therefore have relied on those representations and statements for purposes
of our opinions.
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. Included among the Managing General
Partner's representations are the following:
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Atlas Resources, Inc.
February 18, 2005
Page 4
o The Partnership Agreement will be duly executed by the Managing
General Partner and the Participants in each Partnership and
recorded in all places required under the Delaware Revised
Uniform Limited Partnership Act and any other applicable limited
partnership act. Also, each Partnership will operate its
business as described in the Prospectus and in accordance with
the terms of the Partnership Agreement, the Delaware Revised
Uniform Limited Partnership Act, and any other applicable
limited partnership act.
o 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 Neither Partnership will elect to be taxed as a corporation.
o Each Partnership will own only Working Interests in all of its
Prospects.
o Neither Partnership's Units will be traded on an established
securities market.
o A typical Participant in each Partnership will be a natural
person who purchases Units in this offering and is a U.S.
citizen.
o The Investor General Partner Units in a Partnership will not be
converted by the Managing General Partner to Limited Partner
Units until after all of the wells in that Partnership have been
drilled and completed. The Managing General Partner anticipates
that all of the productive wells in each Partnership will be
drilled, completed and placed in service no more than 12 months
after that Partnership's final closing. Thus, the Managing
General Partner anticipates that conversion will be in 2006 for
both Atlas America Public #14-2005(A) L.P. and Atlas America
Public #14-2005(B) L.P.
o Each Partnership ultimately will own legal title to its Working
Interest in all of its Prospects, although initially title to
the Prospects will be held in the name of the Managing General
Partner, its Affiliates or other third-parties as nominee for
the Partnership, in order to facilitate the acquisition of the
Leases.
o The entire Working Interest in most, if not all, of each
Partnership's Prospects will be assigned to that Partnership,
however, the Managing General Partner anticipates that each
Partnership will acquire less than 100% of the Working Interest
in one or more of its Prospects, and although prepayments of
Intangible Drilling Costs and the Participants' share of the
Tangible Costs will be required of each Partnership under its
Drilling and Operating Agreement with the Managing General
Partner, acting as general drilling contractor, the other owners
of Working Interests in those wells will not be required to
prepay any of their share of the costs of drilling the wells.
o Each Partnership will make the election under Section 263(c) of
the Code and Treas. Reg. Section 1.612-4(a) to expense, rather
than capitalize, 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 2002 by an independent industry association which surveyed
other non-affiliated operators in the area, and information it
has concerning increases in drilling costs in the area since
then, the amounts that will be paid by the Partnerships to the
Managing General Partner or its Affiliates under the Drilling
and Operating Agreement to drill and complete each Partnership's
wells at Cost plus 15% are reasonable and competitive amounts
that ordinarily would be
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Atlas Resources, Inc.
February 18, 2005
Page 5
paid for similar services in similar transactions between
Persons having no affiliation and dealing with each other "at
arms' length" in the proposed areas of operations.
o For its services as general drilling contractor, the Managing
General Partner anticipates that on average over all of the
wells drilled and completed by each Partnership, assuming a 100%
Working Interest in each well, it will have reimbursement of
general and administrative overhead of approximately $12,690 per
well and a profit of 15% (approximately $23,976) per well, with
respect to the Intangible Drilling Costs and the portion of
Tangible Costs paid by the Participants in each Partnership as
described in "Compensation - Drilling Contracts" in the
Prospectus.
o Based on the Managing General Partner's experience and its
knowledge of industry practices in the Appalachian Basin, its
allocation of the drilling and completion price to be paid by
each Partnership to the Managing General Partner or its
Affiliates as a third-party general drilling contractor to drill
and complete a well between Intangible Drilling Costs and
Tangible Costs as set forth in "Compensation - Drilling
Contracts" in the Prospectus is reasonable.
o The Managing General Partner anticipates that all of the
subscription proceeds of each Partnership will be expended in
2005, and the related income, if any, and deductions, including
the deduction for Intangible Drilling Costs, will be reflected
on its Participants' federal income tax returns for that period.
o The Managing General Partner does not anticipate that any of the
Partnerships' production of natural gas and oil from their
respective wells in 2005, if any, will qualify for the marginal
well production credit in 2005, because the prices for natural
gas and oil in 2004 were substantially above the $2.00 per mcf
and $18.00 per barrel prices where the credit phases out
completely.
o The Managing General Partner anticipates that Atlas America
Public #14-2005(A) L.P., which has a targeted closing date of
March 31, 2005 (which is not binding on the Partnership), will
drill and complete all of its wells in 2005 and, therefore, will
not prepay in 2005 any of its Intangible Drilling Costs for
drilling activities that will begin in 2006. However, depending
primarily on when it receives its subscription proceeds, Atlas
America Public #14-2005(A) L.P. may have its final closing as
late in the year as December 31, 2005. Therefore, depending
primarily on when its subscription proceeds are received, the
Managing General Partner further anticipates that Atlas America
Public #14-2005(A) L.P. may prepay in 2005 most, if not all, of
its Intangible Drilling Costs for drilling activities that will
begin in 2006. Atlas America Public #14-2005(B) L.P., which will
not begin offering any remaining unsold Units in the Program
until after the final closing of Atlas America Public
#14-2005(A) L.P., also may have its final closing as late as
December 31, 2005, and, therefore, may prepay in 2005 most, if
not all, of its Intangible Drilling Costs for drilling
activities that will begin in 2006.
o Each Partnership will attempt to comply with the guidelines set
forth in Keller v. Commissioner with respect to any prepaid
Intangible Drilling Costs.
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 Section 613A(c)(6)(E) of the Code, and each
Partnership's gross income from the sale of its natural gas and
oil
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Atlas Resources, Inc.
February 18, 2005
Page 6
production will qualify under the Code for the potentially
higher rates of percentage depletion available under the Code
for marginal production of natural gas and oil.
o To the extent a Partnership has cash available for distribution,
it is the Managing General Partner's policy that the
Partnership's cash distributions to its Participants will not be
less than the Managing General Partner's estimate of the
Participants' income tax liability with respect to that
Partnership's income.
o The Managing General Partner does not anticipate that the amount
of its amortization deductions for organization expenses related
to the creation of a Partnership will be material in amount as
compared to the total subscription proceeds of that Partnership.
o The principal purpose of each Partnership is to locate, produce
and market natural gas and oil on a profitable basis, apart from
tax benefits, as discussed in the Prospectus. (See, in
particular, "Prior Activities," "Management," "Proposed
Activities," and "Appendix A" in the Prospectus.)
o Appendix A in the Prospectus will be supplemented or amended to
cover a portion of the specific Prospects proposed to be drilled
by Atlas America Public #14-2005(B) L.P. when Units in that
Partnership are first offered to prospective Participants.
o Due to the restrictions on transfers of Units in the Partnership
Agreement, the Managing General Partner does not anticipate that
either Partnership will ever be considered as terminated under
Section 708(b) of the Code (relating to the transfer of 50% or
more of a Partnership's capital and profits interests in a
12-month period).
o Based in part on its past experience, the Managing General
Partner anticipates that there will be more than 100 Partners in
each Partnership. The Managing General Partner, however, does
not anticipate that either Partnership will elect to be governed
under simplified tax reporting and audit rules as an "electing
large partnership, because most limitations affecting the
calculation of the taxable income and tax credits of an electing
large partnership are applied at the partnership level and not
the partner level.
o Due to the complexities and added expense of the tax accounting
required to implement a Section 754 election to adjust the basis
of a Partnership's property when Units are sold, taking into
account the limitations on the sale of the Partnership's Units,
neither Partnership will make the Section 754 election.
o The Managing General Partner and its Affiliates will not make or
arrange financing for potential Participants to use to purchase
Units in a Partnership.
o The Managing General Partner will notify the Participants of any
IRS audits or other tax proceedings involving their Partnership,
and will provide the Participants any other information
regarding the proceedings as may be required by the Partnership
Agreement or law.
o Each Partnership will provide its Participants with the tax
information applicable to their investment in the Partnership
necessary to prepare their tax returns.
o The Managing General Partner anticipates that each Partnership
will incur a tax Loss during at least its first taxable year,
due primarily to the amount of Intangible Drilling Costs it
intends to claim as a deduction, and that the Loss in each
Partnership's first taxable year will be in an amount equal or
greater
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Atlas Resources, Inc.
February 18, 2005
Page 7
than $1.8 million, with the actual amount of the Loss of each
Partnership depending primarily on the amount of the
Partnership's subscription proceeds.
o The Managing General Partner believes that each productive well
drilled by a Partnership will produce for more than five years,
and that it is likely to be many years after the well was
drilled before its commercial natural gas and oil reserves have
been produced and depleted.
o Based primarily on the Managing General Partner's past
experience as shown in "Prior Activities" in the Prospectus,
each Partnership's total abandonment losses under Section 165 of
the Code, if any, which could include, for example, the
abandonment by a Partnership of wells drilled which are
nonproductive (i.e. a "dry hole") or wells which have been
operated until their commercial natural gas and oil reserves
have been depleted (and each Participant's allocable share of
those abandonment losses), will be less, in the aggregate, than
$2 million in any taxable year of a Partnership and less than an
aggregate total of $4 million during the Partnership's first six
taxable years.
o The Managing General Partner does not anticipate that the
Partnerships will have a significant book-tax difference for
purposes of the reportable transaction rules in any of their
taxable years since under those rules book-tax differences
arising from depletion, Intangible Drilling Costs, and
depreciation and amortization methods, useful lives, etc. are
not taken into account.
o No productive well of a Partnership which may generate marginal
well production tax credits will be held by the Partnership for
45 days or less. In addition, even if all of both Partnerships'
wells were taken into account, which the Managing General
Partner anticipates would be approximately 407 gross wells, any
marginal well production credits arising from the natural gas
and oil production for that short period of time would not
exceed $250,000.
o The Managing General Partner will attempt to eliminate or reduce
any gain to a Partnership from a Farmout, if any.
SCOPE OF OUR REVIEW. We have considered the provisions of 31 CFR, Part 10,
Sections 10.35 and 10.37 (Treasury Department Circular No. 230) on tax law
opinions. We believe that this tax opinion letter and, where appropriate, the
Prospectus fully and fairly address all of the material federal tax issues and
any significant federal tax issues associated with an investment in a
Partnership by a typical Participant. In this regard, the Managing General
Partner has represented that a typical Participant in a Partnership will be a
natural person who purchases Units in a Partnership in this offering and is a
U.S. citizen. For purposes of this tax opinion letter, a federal tax issue is a
question concerning the federal tax treatment of an item of income, gain, loss,
deduction, or credit; the existence or absence of a taxable transfer of
property; or the value of property for federal tax purposes. A federal tax issue
is significant if the IRS has a reasonable basis for a successful challenge and
its resolution could have a significant impact, whether beneficial or adverse
and under any reasonably foreseeable circumstance, on the overall federal tax
treatment of the Partnerships or a Participant's investment in a Partnership. We
consider a federal tax issue to be material if its resolution:
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
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Atlas Resources, Inc.
February 18, 2005
Page 8
o marginal well production credits in excess of the
Participant's tentative regular federal income tax
liability on the Participant's share of his
Partnership's federal net taxable income in any taxable
year; or
o could reasonably affect the potential applicability of federal
tax penalties against the Participants.
Also, in ascertaining that all material federal tax issues and any significant
federal tax issues have been considered, evaluating the merits of those issues
and evaluating whether the federal tax treatment set forth in our opinions is
the proper tax treatment, we have not taken into account the possibility that a
tax return will not be audited, that an issue will not be raised on audit, or
that an issue will be settled.
OPINIONS. Although our opinions express what we believe a court would
probably conclude if presented with the applicable issues, our opinions are only
predictions, and are not guarantees, of the outcome of the particular tax issues
being addressed. The intended federal tax consequences and federal tax benefits
of a Participant's investment in a Partnership are not contractually protected
as described in greater detail in "Risk Factors - Tax Risks - Your Tax Benefits
Are Not Contractually Protected" in the Prospectus. The IRS could challenge our
opinions, and the challenge could be sustained in the courts and cause adverse
tax consequences to the Participants. Taxpayers bear the burden of proof to
support claimed deductions and credits, and our opinions are not binding on the
IRS or the courts. 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. In our opinion
the federal tax treatment with respect to each federal tax issue arising from an
investment in a Partnership by a typical Participant as set forth below is the
proper tax treatment of that issue and will be upheld on the merits if
challenged by the IRS and litigated.
(1) PARTNERSHIP CLASSIFICATION. Each Partnership will be classified
as a partnership for federal income tax purposes, and not as a
corporation. The Partnerships, as such, will not pay any federal
income taxes, and all items of income, gain, loss, deduction,
and credit, if any, of the Partnerships will be reportable by
the Partners in the Partnership in which they invest.
(2) PASSIVE ACTIVITY CLASSIFICATION.
o The passive activity limitations on losses and credits
under Section 469 of the Code will apply to:
o the Limited Partners in a Partnership; and
o will not apply to the Investor General Partners
in the Partnership until after the conversion of
the Investor General Partner Units to Limited
Partner Units in the Partnership.
o A Partnership's income, gain and credits, if any, from
its natural gas and oil properties which are allocated
to its Limited Partners, other than net income and any
related credits allocated to former Investor General
Partners who have been converted to Limited Partners,
will be characterized as:
o passive activity income which may be offset by
passive activity losses; and
o passive activity credits which a Limited Partner
may use to offset a portion or all of the
Limited Partner's regular federal income tax
liability from passive income received by the
Limited Partner from the Partnership or other
passive activities, other than publicly traded
partnership passive activities.
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Atlas Resources, Inc.
February 18, 2005
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o Income or gain attributable to investments of working
capital of a Partnership will be characterized as
portfolio income, which cannot be offset by passive
activity losses, and will not generate any marginal well
production credits.
For a discussion of the types of entities whose investments in a
Partnership also will be subject to the passive activity
limitations on losses and credits, see the Summary Discussion "-
Limitations on Passive Activity Losses and Credits," below.
(3) NOT A PUBLICLY TRADED PARTNERSHIP. Neither Partnership will be
treated as a publicly traded partnership under the Code.
(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 syndication fees and other
items which are required to be capitalized, are currently
deductible.
o POTENTIAL LIMITATIONS ON DEDUCTIONS. A Participant's
ability to use the Participant's share of these
deductions on the Participant's personal 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 the Participant's taxable
income, alternative minimum taxable income,
losses, deductions, exemptions, etc., which are
not related to the Participant's investment in a
Partnership;
o the amount of the Participant's adjusted basis
in the Participant's Units 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 in the case of the Limited Partners (including
the Investor General Partners after their Units
are converted to Limited Partner Units by their
Partnership) who are natural persons, the
passive activity limitations on losses and
credits.
See "- Tax Basis of Units," "- 'At Risk' Limitation For Losses,"
"- Alternative Minimum Tax" and "- Limitations on Passive
Activity Losses and Credits" in the Summary Discussion section
of this tax opinion letter.
(5) INTANGIBLE DRILLING COSTS. Although each Partnership will elect
to deduct currently all Intangible Drilling Costs, each
Participant may still elect to capitalize and deduct all or part
of his share of his Partnership's Intangible Drilling Costs
(other than drilling and completion costs of a re-entry well
which are not related to deepening the well) ratably over a 60
month period as discussed in "- Alternative Minimum Tax," below.
Subject to the foregoing, Intangible Drilling Costs paid by a
Partnership under the terms of bona fide drilling contracts for
the Partnership's wells will be deductible by Participants who
elect to currently deduct their share of their Partnership's
Intangible Drilling Costs in the taxable year in which the
payments are made and the drilling services are rendered.
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Atlas Resources, Inc.
February 18, 2005
Page 10
A Participant's ability to use the Participant's share of these
deductions on the Participant's personal federal income tax
returns may be reduced, eliminated or deferred by the "Potential
Limitations on Deductions" set forth in opinion (4) above.
(6) PREPAYMENTS OF INTANGIBLE DRILLING COSTS. Subject to each
Participant's election to capitalize and amortize a portion or
all of the Participant's share of his Partnership's deductions
for Intangible Drilling Costs as set forth in opinion (5) above,
any prepayments in 2005 of Intangible Drilling Costs for wells
the drilling of which will not begin until on or before March
31, 2006, by a Partnership will be deductible by the
Participants in that Partnership in 2005.
A Participant's ability to use the Participant's share of these
deductions on the Participant's 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 natural gas and oil production
income, subject to the following restrictions:
o a Participant's cost depletion allowance cannot exceed
the Participant's share of the adjusted tax basis of the
natural gas or oil property to which it relates; and
o a Participant's percentage depletion allowance:
o may not exceed 100% of the Participant's share
of his Partnership's net income from each
natural gas and oil property before the
deduction for depletion, however, this
limitation is suspended in 2005 with respect to
marginal properties; and
o is limited to 65% of the Participant's taxable
income for the year computed without regard to
percentage depletion, net operating loss
carry-backs and capital loss carry-backs.
See "- Depletion Allowance" in the Summary Discussion section of
this tax opinion letter.
(8) MACRS. Each Partnership's reasonable costs for equipment placed
in its respective productive wells which cannot be deducted
immediately ("Tangible Costs") will be eligible for cost
recovery deductions under the Modified Accelerated Cost Recovery
System ("MACRS") over a seven year "cost recovery period"
beginning in the taxable year each well is drilled, completed
and made capable of production, i.e. placed in service.
A Participant's ability to use the Participant's share of these
deductions on the Participant's 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 will be the amount of money that the
Participant paid for his Units.
(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 the Participant paid for his Units.
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February 18, 2005
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(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.
(12) SUBSCRIPTION. No gain or loss will be recognized by the
Participants on payment of their subscriptions to the
Partnership in which they invest.
(13) PROFIT MOTIVE, IRS ANTI-ABUSE RULE AND POTENTIALLY RELEVANT
JUDICIAL DOCTRINES. The Partnerships will possess the requisite
profit motive under Section 183 of the Code. Also, the IRS
anti-abuse rule in Treas. Reg. Section 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.
(14) REPORTABLE TRANSACTIONS. It is more likely than not that each
Partnership will not be a reportable transaction under the Code,
and their Participants will not be subject to the reportable
transaction understatement penalty under the Code with respect
to their investment in a Partnership.
(15) OVERALL CONCLUSION. Our overall conclusion is that the federal
tax treatment of a typical Participant's investment in a
Partnership as set forth above in our opinions is the proper
federal tax treatment and will be upheld on the merits if
challenged by the IRS and litigated. The reason we have reached
this overall conclusion is that our evaluation of the federal
income tax laws and the expected activities of the Partnerships
as represented to us by the Managing General Partner in this tax
opinion letter and as described in the Prospectus causes us to
believe that the deduction by a Participant of all, or
substantially all, of his allocable share of his Partnership's
Intangible Drilling Costs in 2005 (even if the drilling of a
portion or all of his Partnership's wells begins after December
31, 2005, but on or before March 31, 2006), as set forth in
opinions (5) and (6) above, is the principal tax benefit offered
by the Partnerships to potential Participants and is also the
proper federal tax treatment, subject to each Participant's
election to capitalize and amortize a portion or all of the
Participant's deduction for Intangible Drilling Costs as
discussed in the Summary Discussion "- Alternative Minimum Tax,"
below.
A Participant's ability to use the Participant's share of these
deductions on the Participant's 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 "MATERIAL
FEDERAL INCOME TAX CONSEQUENCES," insofar as it contains
statements of federal income tax law, is correct in all material
respects.
SUMMARY DISCUSSION OF THE MATERIAL FEDERAL INCOME TAX
CONSEQUENCES AND ANY SIGNIFICANT FEDERAL TAX ISSUES OF AN INVESTMENT IN
A PARTNERSHIP (THE "SUMMARY DISCUSSION")
INTRODUCTION. Our tax opinions are limited to those set forth above. The
following is a summary of all of the material federal income tax consequences,
and any significant federal tax issues, of the purchase, ownership and
disposition of a Partnership's Units which will apply to typical Participants in
each Partnership. Except as otherwise noted below, however, different tax
considerations 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, partnerships, trusts, and other prospective Participants
which are subject to special treatment under the Code and are not treated as
typical Participants
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February 18, 2005
Page 12
for federal income tax purposes. Also, the proper treatment of the tax
attributes of a Partnership by a typical Participant on his individual federal
income tax return may vary from that by another typical Participant. This is
because the practical utility of the tax aspects of any investment depends
largely on each Participant's particular income tax position in the year in
which items of income, gain, loss, deduction, or credit, if any, are properly
taken into account in computing the Participant's federal income tax liability.
In addition, the IRS may challenge the deductions and credits claimed by a
Partnership or a Participant, or the taxable year in which the deductions and
credits are claimed, and it is possible that the challenge would be upheld if
litigated. Accordingly, each prospective Participant is urged to seek qualified,
professional advice based on the Participant's particular circumstances from an
independent tax advisor in evaluating the potential tax consequences to him of
an investment in a Partnership.
PARTNERSHIP CLASSIFICATION. For federal income tax purposes a
partnership is not a taxable entity. Thus, the partners, rather than the
partnership, report their share of all items of income, gain, loss, deduction,
tax credits, and tax preferences from the partnership's operations on their
personal federal income tax return. A business entity with two or more members
is classified for federal tax purposes as either a corporation or a partnership.
Treas. Reg. Section 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. Section 301.7701-2(b). Each Partnership, however, has been formed as
a limited partnership under the Delaware Revised Uniform Limited Partnership Act
which describes each Partnership as a "partnership." Thus, each Partnership
automatically will be classified as a partnership since the Managing General
Partner has represented that neither Partnership will elect to be taxed as a
corporation.
LIMITATIONS ON PASSIVE ACTIVITY LOSSES AND CREDITS. Under the passive
activity rules of Section 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 Sections 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 Section 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
Section 501(c)(17) of the Code, domestic or foreign "private
foundations" described in Section 501(c)(3) of the Code, and a
portion of a trust permanently set aside
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Atlas Resources, Inc.
February 18, 2005
Page 13
or to be used exclusively for the charitable purposes described
in Section 642(c) of the Code or a corresponding provision of a
prior income tax law, are considered to be individuals); and
o a personal service corporation, which under Sections 469(j)(2),
269A(b) and 318(a)(2)(C) of the Code means a corporation the
principal activity of which is the performance of personal
services and those services are substantially performed by
employee-owners. For this purpose, 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 Section 469 of the
Code unless more than 10% of the stock (by value) in the
corporation is held by employee-owners (as described above).
However, a closely held C corporation, other than a personal service
corporation, may use passive losses and credits to offset taxable income of the
company figured without regard to passive income or loss or portfolio income.
Passive activities include any trade or business in which the taxpayer does not
materially participate on a regular, continuous, and substantial basis. Under
the Partnership Agreement, Limited Partners will not have material participation
in the Partnership in which they invest and will be subject to the passive
activity limitations on losses and credits if they are included as taxpayers who
are subject to Section 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.
Section 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.
Contractual limitations on the liability of Investor General Partners under the
Partnership Agreement, as compared with limitations on liability under state law
as discussed above, such as insurance, limited indemnification by the Managing
General Partner, etc. will not cause Investor General Partners to be subject to
the passive activity loss limitations. Investor General Partners, however, may
be subject to an additional limitation on their deduction of investment interest
expense as
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Atlas Resources, Inc.
February 18, 2005
Page 14
a result of their deduction of Intangible Drilling Costs. (See "- Limitations on
Deduction of Investment Interest," below.)
A Limited Partner's "at risk" amount is reduced by losses allowed under
Section 465 of the Code even if the losses are suspended by the passive activity
loss limitation. (See "- 'At Risk' Limitation For Losses," below.) Similarly, a
Limited Partner's basis is reduced by deductions even if the deductions are
suspended under the passive activity loss limitation. (See "- Tax Basis of
Units," below.)
Suspended 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 used to offset future years' passive activity income, or used to
offset passive activity regular income tax liability (in the case of passive
activity credits). A suspended loss, but not a credit, is allowed in full when
the entire interest in a passive activity is sold to an unrelated third-party in
a taxable transaction, and in part on the disposition of substantially all of
the interest in a passive activity if the suspended loss as well as current
gross income and deductions can be allocated to the part disposed of with
reasonable certainty. In an installment sale, passive losses and credits become
available in the same ratio that gain recognized each year bears to the total
gain on the sale.
Any suspended losses remaining at a taxpayer's death are allowed as
deductions on the decedent's final return, subject to a reduction to the extent
the basis of the property in the hands of the transferee exceeds the property's
adjusted basis immediately before the decedent's death. If a taxpayer makes a
gift of his entire interest in a passive activity, the basis in the property of
the person receiving the gift is increased by any suspended losses and no
deductions are allowed. If the interest is later sold at a loss, the basis in
the property of the person receiving the gift is limited to the fair market
value on the date the gift was made.
PUBLICLY TRADED PARTNERSHIP RULES. Net losses and most net credits of a
partner from a publicly traded partnership are suspended and carried forward to
be netted against income or regular federal income tax liability, respectively,
from that publicly traded partnership only. In addition, net losses from other
passive activities may not be used to offset net passive income from a publicly
traded partnership. I.R.C. Sections 469(k)(2) and 7704. A publicly traded
partnership is a partnership in which interests in the partnership are traded on
an established securities market, or in which interests in the partnership are
readily tradable on either a secondary market or the substantial equivalent of a
secondary market. However, in our opinion neither Partnership will be treated as
a publicly traded partnership under the Code. This opinion is based primarily on
the substantial restrictions in the Partnership Agreement on each Participant's
ability to transfer his Units in the Partnership in which he invests. (See
"Transferability of Units - Restrictions on Transfer Imposed by the Securities
Laws, the Tax Laws and the Partnership Agreement" in the Prospectus.) Also, the
Managing General Partner has represented that neither Partnership's Units will
be traded on an established securities market.
CONVERSION FROM INVESTOR GENERAL PARTNER TO LIMITED PARTNER. If a
Participant invests in a Partnership as an Investor General Partner, then his
share of the Partnership's deduction for Intangible Drilling Costs in 2005 will
not be subject to the passive activity loss limitation. This is because the
Managing General Partner has represented that the Investor General Partner Units
in a Partnership will not be converted by the Managing General Partner to
Limited Partner Units until after all of the wells in that Partnership have been
drilled and completed. In this regard, the Managing General Partner anticipates
that all of the productive wells in each Partnership will be drilled, completed
and placed in service no more than 12 months after that Partnership's final
closing. Thus, the Managing General Partner anticipates that conversion will be
in 2006 for both Atlas America Public #14-2005(A) L.P. and Atlas America Public
#14-2005(B) L.P. (See "Actions to be Taken by Managing General Partner to Reduce
Risks of Additional Payments by Investor General Partners" in the Prospectus,
and "- Drilling Contracts," below.) After the Investor General Partner Units
have been converted to Limited Partner Units, each former Investor General
Partner will have limited liability as a limited partner under the Delaware
Revised Uniform Limited Partnership Act with respect to his interest in his
Partnership's activities after the date of the conversion.
KUNZMAN & BOLLINGER, INC.
Atlas Resources, Inc.
February 18, 2005
Page 15
Concurrently, the former Investor General Partner will become subject to
the passive activity rules as a limited partner. However, the former Investor
General Partner previously will have received a non-passive loss as an Investor
General Partner in 2005 as a result of the Partnership's deduction for
Intangible Drilling Costs. Therefore, the Code requires that his net income from
the Partnership's wells after his conversion to a limited partner must continue
to be characterized as non-passive income which cannot be offset with passive
losses. I.R.C. Section 469(c)(3)(B). For a discussion of the effect of this rule
on an Investor General Partner's tax credits from his Partnership, if any, see "
- - Marginal Well Production Credits," below. The conversion of the Investor
General Partner Units into Limited Partner Units should not have any other
adverse tax consequences on an Investor General Partner unless his share of any
Partnership liabilities is reduced as a result of the conversion. Rev. Rul.
84-52, 1984-1 C.B. 157. A reduction in a partner's share of liabilities is
treated as a constructive distribution of cash to the partner, which reduces the
basis of the partner's interest in the partnership and is taxable to the extent
it exceeds his basis. (See "- Tax Basis of Units," below.)
TAXABLE YEAR. Each Partnership will have a calendar year taxable year.
I.R.C. Sections 706(a) and (b). The taxable year of a Partnership is important
to a Participant because the Partnership's deductions, tax credits, if any,
income and other items of tax significance must be taken into account on the
Participant's personal federal income tax return for his taxable year within or
with which the Partnership's taxable year ends. The tax year of a partnership
must be the majority interest taxable year, which is defined under Section
706(b)(1)(B)(i) of the Code as the taxable year of one or more of its partners
who have, on each testing day, an aggregate interest in partnership profits and
capital of more than 50%, unless there is no majority interest taxable year. In
the case of the Partnerships, however, typical Participants who have calendar
year taxable years will own more than 50% of each Partnership's profits and
capital interests at all times during the term of each Partnership.
METHOD OF ACCOUNTING. Each Partnership will use the accrual method of
accounting for federal income tax purposes. I.R.C. Section 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 Section 461(h) of the Code, if the liability of the taxpayer
arises out of the providing of services or property to the taxpayer by another
person, economic performance occurs as the services or property, respectively,
are provided. If the liability of the taxpayer arises out of the use of the
property by the taxpayer, economic performance occurs as the property is used.
o A special rule in the Code, however, provides that there is
economic performance in the current taxable year with respect to
amounts paid in that taxable year for Intangible Drilling Costs
of drilling and completing a natural gas or oil well so long as
the drilling of the well begins before the close of the 90th day
after the close of the taxable year in which the payments were
made. I.R.C. Section 461(i). (See "- Drilling Contracts," below,
for a discussion of the tax treatment of any prepaid Intangible
Drilling Costs by Atlas America Public #14-2005(A) L.P. and
Atlas America Public #14-2005(B) L.P.)
2005 EXPENDITURES. The Managing General Partner anticipates that all of
the subscription proceeds of each Partnership will be expended in 2005, and the
related income and deductions, including the deduction for Intangible Drilling
Costs, will be reflected on its Participants' federal income tax returns for
that period. (See "Capitalization and Source of Funds and Use of Proceeds" and
"Participation in Costs and Revenues" in the Prospectus.) In this regard, the
Managing General Partner does not anticipate that any of the Partnerships'
production of natural gas and oil from their respective wells in 2005, if any,
will qualify for the marginal well production credit in 2005, because the prices
for natural gas and oil in 2004 were substantially above the $2.00 per mcf and
$18.00 per barrel prices where the credit phases out completely. (See "-
Drilling Contracts" and "- Marginal Well Production Credits," below.)
KUNZMAN & BOLLINGER, INC.
Atlas Resources, Inc.
February 18, 2005
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Depending primarily on when each Partnership's subscriptions are
received, the Managing General Partner anticipates that either or both of Atlas
America Public #14-2005(A) L.P. and Atlas America Public #14-2005(B) L.P., which
may both have their final closing on any date up to and including December 31,
2005, may prepay in 2005 most, if not all, of its respective Intangible Drilling
Costs for drilling activities that will begin in 2006. However, Atlas America
Public #14-2005(A) L.P. has a targeted closing date of March 31, 2005 (which is
not binding on the Partnership), and depending primarily on when it receives its
subscriptions, it may not prepay in 2005 any of its Intangible Drilling Costs
for drilling activities that will begin in 2006. The offering of Units in Atlas
America Public #14-2005(B) L.P. will not begin until after the final closing of
Atlas America Public #14-2005(A) L.P. (See "- Drilling Contracts," below.)
BUSINESS EXPENSES. Ordinary and necessary business expenses, including
reasonable compensation for personal services actually rendered, are deductible
in the year incurred. Treasury Regulation Section 1.162-7(b)(3) provides that
reasonable compensation is only the amount as would ordinarily be paid for like
services by like enterprises under like circumstances. In this regard, the
Managing General Partner has represented that the amounts that will be paid by
the Partnerships to it or its Affiliates under the Drilling and Operating
Agreement to drill and complete each Partnership's wells at Cost plus 15% are
reasonable and competitive amounts that ordinarily would be paid for similar
services in similar transactions between Persons having no affiliation and
dealing with each other "at arms' length" in the proposed areas of both
Partnerships' operations. (See "Compensation" in the Prospectus and "- Drilling
Contracts," below.) The fees paid to the Managing General Partner and its
Affiliates by the Partnerships will not be currently deductible, however, to the
extent it is determined by the IRS or the courts that they are:
o in excess of reasonable compensation;
o properly characterized as organization or syndication fees or
other capital costs such as the acquisition cost of the Leases;
or
o not "ordinary and necessary" business expenses.
(See "- Partnership Organization and Offering Costs," below.) In the event of an
audit, payments to the Managing General Partner and its Affiliates by a
Partnership will be scrutinized by the IRS to a greater extent than payments to
an unrelated party.
A Participant's ability to use the Participant's share of these
deductions on the Participant's 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 the Partnership's wells
are drilled and completed. I.R.C. Section 263(c), Treas. Reg. Section
1.612-4(a). For a discussion of the earlier deduction of prepaid Intangible
Drilling Costs, see "- Drilling Contracts," below.
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
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Atlas Resources, Inc.
February 18, 2005
Page 17
deepening the well and completing it to deeper reservoirs, if any, other than
Tangible Costs and Lease Costs, will be treated as Intangible Drilling Costs.
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. (See "Participation in Costs and Revenues" in
the Prospectus.)
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) are subject to recapture as ordinary income rather than
capital gain on the sale or other taxable disposition of the property or a
Participant's Units. (See "- Sale of the Properties" and "- Disposition of
Units," below.) Also, productive-well Intangible Drilling Costs may subject a
Participant to an alternative minimum tax in excess of regular tax unless the
Participant elects to deduct all or part of these costs ratably over a 60 month
period. (See "- Alternative Minimum Tax," below.)
Under the Partnership Agreement, not less than 90% of the subscription
proceeds received by each Partnership from its Participants will be used to pay
100% of the Partnership's Intangible Drilling Costs of drilling and completing
its wells. (See "Application of Proceeds" and "Participation in Costs and
Revenues" in the Prospectus.) The IRS could challenge the characterization of a
portion of these costs as currently deductible Intangible Drilling Costs and
recharacterize the costs as some other item which may not be currently
deductible. However, this would have no effect on the allocation and payment of
the Intangible Drilling Costs by the Participants under the Partnership
Agreement.
In the case of corporations, other than S corporations, which are
"integrated oil companies," the amount allowable as a deduction for Intangible
Drilling Costs in any taxable year is reduced by 30%. I.R.C. Section 291(b)(1).
Integrated oil companies are:
o those taxpayers who directly or through a related person engage
in the retail sale of natural gas and oil and whose gross
receipts for the taxable year from such activities exceed
$5,000,000; or
o those taxpayers and related persons who have refinery production
in excess of 50,000 barrels on any day during the taxable year.
I.R.C. Section 291(b)(4).
Amounts disallowed as a current deduction are allowable as a deduction
ratably over the 60-month period beginning with the month in which the costs are
paid or incurred. The Partnerships will not be integrated oil companies.
A Participant's ability to use the Participant's share of these
deductions on the Participant's personal federal income tax returns may be
reduced, eliminated or deferred by the "Potential Limitations on Deductions" set
forth in opinion (4) in the "Opinions" section of this tax opinion letter above.
Each Participant is urged to seek advice based on his particular
circumstances from an independent tax advisor concerning the tax benefits to him
of the deduction for Intangible Drilling Costs in the Partnership in which he
invests.
DRILLING CONTRACTS. Each Partnership will enter into the Drilling and
Operating Agreement with the Managing General Partner or its Affiliates, acting
as a third-party general drilling contractor, to drill and complete the
Partnership's development wells on a Cost plus 15% basis. For its services as
general drilling contractor, the Managing General Partner anticipates that on
average over all of the wells drilled and completed by each Partnership,
assuming a 100% Working Interest in each well, it will have reimbursement of
general and administrative overhead of approximately $12,690 per well and a
profit of 15% (approximately $23,976) per well, with respect to the Intangible
Drilling Costs and the portion of
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Atlas Resources, Inc.
February 18, 2005
Page 18
Tangible Costs paid by the Participants in each Partnership as described in
"Compensation - Drilling Contracts" in the Prospectus. However, the actual cost
of drilling and completing the wells may be more or less than the estimated
amount, due primarily to the uncertain nature of drilling operations. Therefore,
the Managing General Partner's 15% profit per well as described above also could
be more or less than the dollar amount estimated by the Managing General
Partner. The Managing General Partner believes the prices under the Drilling and
Operating Agreement are competitive in the proposed areas of operation.
Nevertheless, the amount of the profit realized by the Managing General Partner
under the Drilling and Operating Agreement could be challenged by the IRS as
being unreasonable and disallowed as a deductible Intangible Drilling Cost. (See
"- Intangible Drilling Costs," above, and "Compensation" and "Proposed
Activities" in the Prospectus.)
Depending primarily on when each Partnership's subscription proceeds are
received, the Managing General Partner anticipates that either or both of the
Partnerships may prepay in 2005 most, if not all, of their respective Intangible
Drilling Costs for drilling activities that will begin in 2006. (See "- 2005
Expenditures," above.) In Keller v. Commissioner, 79 T.C. 7 (1982), aff'd 725
F.2d 1173 (8th Cir. 1984), the Tax Court applied a two-part test for the current
deductibility of prepaid intangible drilling and development costs. The test is:
o the expenditure must be a payment rather than a refundable
deposit; and
o the deduction must not result in a material distortion of income
taking into substantial consideration the business purpose
aspects of the transaction.
The drilling partnership in Keller entered into footage and daywork
drilling contracts which permitted it to terminate the contracts at any time
without default by the driller, and receive a return of the prepaid amounts less
amounts earned by the driller. The Tax Court found that the right to receive, by
unilateral action, a refund of the prepayments on the footage and daywork
drilling contracts rendered the prepayments deposits instead of payments.
Therefore, the prepayments were held to be nondeductible in the year they were
paid to the extent they had not been earned by the driller. The Tax Court
further found that the drilling partnership failed to show a convincing business
purpose for prepayments under the footage and daywork drilling contracts.
The drilling partnership in Keller also entered into turnkey drilling
contracts which permitted it to stop work under the contract at any time and
apply the unearned balance of the prepaid amounts to another well to be drilled
on a turnkey basis. The Tax Court found that these prepayments constituted
"payments" and not nondeductible deposits, despite the right of substitution.
Further, the Tax Court noted that the turnkey drilling contracts obligated "the
driller to drill to the contract depth for a stated price regardless of the
time, materials or expenses required to drill the well," thereby locking in
prices and shifting the risks of drilling from the drilling partnership to the
driller. Since the drilling partnership, a cash basis taxpayer, received the
benefit of the turnkey obligation in the year of prepayment, the Tax Court found
that the amounts prepaid on turnkey drilling contracts clearly reflected income
and were deductible in the year of prepayment.
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
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turnkey arrangements were merely "contracts of convenience" designed to create a
tax deduction in 1974, and that the turnkey contracts constituted assets having
a life beyond the taxable year and that to allow a deduction for their entire
costs in 1974 distorted income. The Tax Court, relying on Keller, held that the
program could deduct the full amount of the payments in 1974. The court found
that the program entered into turnkey contracts, paid a premium to secure the
turnkey obligations, and thereby locked in the drilling price and shifted the
risks of drilling to the general contractor. Further, the court found that by
signing and paying the turnkey obligation, the program got its bargained-for
benefit in 1974, therefore the deduction of the payments in 1974 clearly
reflected income.
Each Partnership will attempt to comply with the guidelines set forth in
Keller with respect to any prepaid Intangible Drilling Costs. The Drilling and
Operating Agreement will require each Partnership to prepay in 2005 all of the
Partnership's share of the estimated Intangible Drilling Costs, and all of the
Participants' share of the Partnership's share of the estimated Tangible Costs,
for drilling and completing specified wells, the drilling of which may begin in
2006. These prepayments of Intangible Drilling Costs should not result in a loss
of a current deduction for the Intangible Drilling Costs if:
o there is a legitimate business purpose for the required
prepayment;
o the contract is not merely a sham to control the timing of the
deduction; and
o there is an enforceable contract of economic substance.
The Drilling and Operating Agreement will require each Partnership to
prepay the Managing General Partner's estimate of the Intangible Drilling Costs
and the Participants' share of the Tangible Costs to drill and complete the
wells specified in the Drilling and Operating Agreement in order to enable the
Operator to:
o begin site preparation for the wells;
o obtain suitable subcontractors at the then current prices; and
o insure the availability of equipment and materials.
Under the Drilling and Operating Agreement excess prepaid Intangible
Drilling Costs, if any, will not be refundable to a Partnership, but instead
will be applied only to Intangible Drilling Cost overruns, if any, on the other
specified wells being drilled or completed by the Partnership or to Intangible
Drilling Costs to be incurred by the Partnership in drilling and completing
substitute wells. Under Keller, a provision for substitute wells should not
result in the prepayments being characterized as refundable deposits.
The likelihood that prepayments of Intangible Drilling Costs will be
challenged by the IRS on the grounds that there is no business purpose for the
prepayments is increased if prepayments are not required with respect to 100% of
the Working Interest in the well. In this regard, the Managing General Partner
anticipates that less than 100% of the Working Interest will be acquired by each
Partnership in one or more of its wells, and prepayments of Intangible Drilling
Costs will not be required of the other owners of Working Interests in those
wells. In our view, however, a legitimate business purpose for the required
prepayments of Intangible Drilling Costs by the Partnerships may exist under the
guidelines set forth in Keller, even though prepayments are not required by the
drilling contractor with respect to a portion of the Working Interest in the
wells.
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. Section 461(i). (See "- Method of Accounting," above.) Therefore, under
each Partnership's Drilling and Operating Agreement,
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the Managing General Partner as operator and general drilling contractor must
begin drilling each of the prepaid wells, if any, of both Partnerships before
the close of the 90th day after the close of the Partnership's taxable year in
which the prepayment was made, which is March 31, 2006 for both Partnerships.
However, the drilling of any Partnership Well may be delayed due to
circumstances beyond the control of the Managing General Partner or the drilling
subcontractors. These circumstances include, for example:
o the unavailability of drilling rigs;
o decisions of third-party operators to delay drilling the wells;
o poor weather conditions;
o inability to obtain drilling permits or access right to the
drilling site; or
o title problems;
and the Managing General Partner will have no liability to any Partnership or
its Participants if these types of events delay beginning the drilling of the
prepaid wells past the close of the 90th day after the close of the
Partnership's taxable year (i.e., March 31, 2006).
If the drilling of a prepaid Partnership Well in a Participant's
Partnership does not begin on or before the close of the 90th day after the
close of the Partnership's taxable year in which the prepayment was made (i.e.,
March 31, 2006), deductions claimed by a Participant in that Partnership for
prepaid Intangible Drilling Costs for the well in 2005, the year in which the
Participant invested in the Partnership, would be disallowed and deferred to the
next taxable year, 2006, when the well is actually drilled.
A Participant's ability to use the Participant's share of these
deductions on the Participant's personal federal income tax returns may be
reduced, eliminated or deferred by the "Potential Limitations on Deductions" set
forth in opinion (4) in the "Opinions" section of this tax opinion letter above.
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. Sections 611, 613 and 613A. These deductions are subject to
recapture as ordinary income rather than capital gain on the sale or other
taxable disposition of the property or a Participant's Units. (See "- Sale of
the Properties" and "- Disposition of Units," below.)
Cost depletion for any year is determined by dividing the adjusted tax
basis for the property by the total units of natural gas or oil expected to be
recoverable from the property and then multiplying the resultant quotient by the
number of units actually sold during the year. Cost depletion cannot exceed the
adjusted tax basis of the property to which it relates.
Percentage depletion is available to taxpayers other than "integrated
oil companies" as that term is defined in "- Intangible Drilling Costs," above,
which does not include the Partnerships. Percentage depletion is based on a
Participant's share of his Partnership's gross production income from its
natural gas and oil properties. Under Section 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.
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February 18, 2005
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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. Section 613A(c)(6). The term "marginal production" includes natural gas
and oil produced from a domestic stripper well property, which is defined in
Section 613A(c)(6)(E) of the Code as any property which produces a daily average
of 15 or less equivalent barrels of oil, which is equivalent to 90 mcf of
natural gas, per producing well on the property in the calendar year. The
Managing General Partner has represented that most, if not all, of the natural
gas and oil production from each Partnership's productive wells will be marginal
production under this definition in the Code. Therefore, most, if not all, of
each Partnership's gross income from the sale of its natural gas and oil
production will qualify for these potentially higher rates of percentage
depletion. The rate of percentage depletion for marginal production in 2005 is
15%. This rate may fluctuate from year to year depending on the price of oil,
but will not be less than the statutory rate of 15% nor more than 25%.
Also, percentage depletion:
(i) may not exceed 100% of the net income from each natural gas and
oil property before the deduction for depletion, however, this
limitation is suspended in 2005 with respect to marginal
properties (see I.R.C. Section 613A (c)(6)(H)), which the
Managing General Partner has represented will include most, if
not all, of each Partnership's wells; and
(ii) is limited to 65% of the taxpayer's taxable income for the year
computed without regard to percentage depletion, net operating
loss carry-backs and capital loss carry-backs.
Availability of percentage depletion must be computed separately by each
Participant and not by a Partnership or for Participants in a Partnership as a
whole. Potential Participants are urged to seek advice based on their particular
circumstances from an independent tax advisor with respect to the availability
of percentage depletion to them.
MARGINAL WELL PRODUCTION CREDITS. Under the American Jobs Creation Act
of 2004, beginning in 2005 there is a marginal well production credit of
50(cent) per mcf of qualified natural gas production and $3 per barrel of
qualified oil production for purposes of the regular federal income tax. This
credit is part of the general business credit under Section 38 of the Code, but
is not one of the specified energy credits which can be used against the
alternative minimum tax. (See "- Alternative Minimum Tax," below.) Because
natural gas and oil production which qualifies as marginal production under the
percentage depletion rules discussed above, which the Managing General Partner
has represented will include most, if not all, of the natural gas and oil
production from each Partnership's productive wells, is also qualified marginal
production for purposes of this credit, the natural gas and oil production from
most, if not all, of each Partnership's wells will also be eligible for this
credit. To the extent a Participant's share of his Partnership's marginal well
production credits, if any, exceeds the Participant's regular federal income tax
owed on his share of his Partnership's taxable income, the excess credits, if
any, can be used by the Participant to offset any other regular federal income
taxes owed by the Participant, on a dollar-for-dollar basis, subject to the
passive activity loss limitation in the case of Limited Partners. (See "-
Limitations on Passive Activity Losses and Credits," above.)
The marginal well production credit under Section 45I of the Code for
any tax year will be an amount equal to the product of:
o the credit amount; and
o the qualified natural gas production and the qualified crude oil
production which is attributable to the taxpayer.
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February 18, 2005
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Also, the marginal well production credit does not reduce any otherwise
allowable deduction (e.g. depletion) or reduce the taxpayer's adjusted basis in
the qualified marginal well.
The credit will be reduced proportionately for reference prices between
$1.67 and $2.00 per mcf for natural gas and $15 and $18 per barrel for oil. The
applicable reference price for a tax year is the reference price of the calendar
year preceding the calendar year in which the tax year begins. Thus, the
reference prices are determined on a one-year look-back basis.
The reference price for oil was $27.56 in 2003 (IRS Notice 2004-33,
I.R.B. 2004-18), and it has not been under the $18.00 threshold necessary to
qualify for any marginal well production credit for oil since 1999. Similarly,
the Managing General Partner received an average selling price after deducting
all expenses, including transportation expenses, of approximately $4.78 per mcf
in 2003, and the average price it has received for natural gas production in
each calendar year since 1999 has not been less than the $3.30 it received in
2000. In this regard, the Managing General Partner has represented that it does
not anticipate that any of the Partnerships' production of natural gas and oil
from their respective wells in 2005, if any, will qualify for the marginal well
production credit in 2005, because the prices for natural gas and oil in 2004
were substantially above the $2.00 per mcf of natural gas and $18.00 per barrel
of oil prices where the credit phases out completely. Based on the prices set
forth in "Proposed Activities - Sale of Natural Gas and Oil Production" in the
Prospectus for natural gas and oil in the past several years, it may appear
unlikely that a Partnership's natural gas and oil production will ever qualify
for this credit. However, prices for natural gas and oil are volatile and could
decrease in the future. (See "Risk Factors - Risks Related To The Partnerships'
Oil and Gas Operations - Partnership Distributions May be Reduced if There is a
Decrease in the Price of Natural Gas and Oil," in the Prospectus.) Thus, it is
possible that the Partnerships' production of natural gas or oil in one or more
taxable years after 2005 could qualify for the marginal well production credit,
depending primarily on the applicable reference prices for natural gas and oil
in the future.
A qualified marginal well is a well which is located in the United
States or its possessions:
o the production from which during the tax year is treated as
marginal production under the percentage depletion rules of
Section 613A(c)(6) of the Code; or
o which, during the tax year, in the case of a natural gas well,
has average daily production of not more than 25 barrel-of-oil
equivalents, and produces water at a rate not less than 95% of
total well effluent.
For purposes of the percentage depletion rules, Section 613A(c)(6)(D) of
the Code defines "marginal production" as domestic natural gas or crude oil
produced from a property that is:
o a stripper well property (i.e. a property which has average
daily production of 15 or less barrel equivalents of natural gas
and oil per well, based on all of the producing wells on the
property); or
o a heavy oil property.
As noted above, Section 45I(c)(3)(A)(i) of the Code incorporates the
definition of marginal property that is used for purposes of the increased
percentage depletion rate that applies when the reference price of crude oil is
less than $20. Therefore, any property that qualifies for the increased
percentage depletion rate may also qualify for this credit. The same definition
of marginal property also applies for purposes of the suspension in 2005 of the
100%-of-taxable income limitation on percentage depletion for oil and gas
produced from marginal properties. (See "- Depletion Allowance," above.)
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February 18, 2005
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The maximum amount of marginal production of natural gas and oil from a
well on which the credit can be claimed by a Partnership in any taxable year is
1,095 barrels of oil or barrel-of-oil equivalents per well. For a well which is
not capable of production during each day of a tax year, the 1,095 barrel
limitation for oil and the barrel-of-oil equivalent limitation for natural gas
for each well will be proportionately reduced to reflect the ratio which the
number of days of production bears to the total number of days in the tax year.
Under Section 613A(e)(4) of the Code, a "barrel" of oil means 42 U.S. gallons.
Under Section 29(d)(5) of the Code, the term "barrel-of-oil equivalent" means
that amount of fuel which has a Btu ("British thermal unit") content of 5.8
million. Therefore, the maximum barrel-of-oil equivalent of natural gas per well
for which the credit is available is 6,351,000,000 Btus (1,095 barrels of oil x
5,800,000 Btus). These Btus must be converted to mcfs, since the credit is based
on mcfs. According to the Energy Information Administration, one cubic foot of
natural gas is approximately equal to 1,021 Btus. Using this conversion ratio,
the number of cubic feet of natural gas in 6,351,000,000 Btus is approximately
6,220,372 (6,351,000,000 / 1,021) cubic feet of natural gas. Since the credit
will be 50(cent) per 1,000 cubic feet ("mcf") of natural gas, this amount is
rounded down to 6,220,000 cubic feet of natural gas (6,220 mcf). Under this
example, the well could produce a little more than an average of 17 mcf of
natural gas per day (6,220 mcf / 365 days= 17.04 mcf of natural gas per day)
that may qualify for the marginal well production credit.
Subject to a post-2005 inflation adjustment, the maximum dollar amount
of the credit in any tax year will be $3,110 (6,220 mcf x 50(cent)) for
qualified natural gas production from each qualified marginal well, as explained
above, and $3,285 ($3.00 x 1,095 barrels) for qualified crude oil production
from each qualified marginal well. There is no limit on the number of qualified
marginal wells on which a Partnership and its Participants can claim the credit.
Only holders of a Working Interest in a qualified well can claim the
credit. For purposes of the credit, the Participants in a Partnership will be
treated as Working Interest owners because of their flow-through ownership
interest in the Partnership. In this regard, the Managing General Partner has
represented that each Partnership will own only Working Interests in all of its
Prospects. As a result of this rule, owners of non-Working Interests in a well,
such as the owner of a Landowner's Royalty Interest, will not receive any of
these credits from the well. For a qualified marginal well in which there is
more than one owner of the Working Interests, which will be the case for one or
more wells in each Partnership, if the natural gas or oil production from the
well exceeds the 1,095 barrel limitation for oil or the barrel-of-oil equivalent
for natural gas (determined at the Partnership level, and not the Participant
level), then the amount of qualifying natural gas and oil production that each
owner of a partial Working Interest in the well is entitled to will be based on
the ratio which each Working Interest owner's revenue interest in the production
from the well bears to the aggregate of the revenue interests of all Working
Interest owners in the production from the well. (See "Proposed Activities -
Interests of Parties" in the Prospectus.) Each Participant in a Partnership will
share in his Partnership's marginal well production credits, if any, in the same
proportion as his share of the Partnership's production revenues. (See
"Participation in Costs and Revenues" in the Prospectus.)
Unused marginal natural gas and oil well production credits can be
carried back for up to five years. Also, the carryforward period for marginal
natural gas and oil well production credits is 20 years, the same as for other
general business credits. However, unlike many other credits that comprise the
general business credit under Section 38 of the Code, the marginal well
production credit is not a "qualified business credit" under Section 196(c) of
the Code. Thus, a Participant will not be able to deduct any marginal well
production credits under Section 196 of the Code that remain unused at the end
of the twenty-year carryforward period.
Under Section 469(c)(3) of the Code, an Investor General Partner's share
of his Partnership's marginal well production credits, if any, will be an active
credit which may offset the Investor General Partner's regular federal income
tax liability on any type of income. However, after the Investor General Partner
is converted to a Limited Partner in his Partnership, his share of the
Partnership's marginal well production credits, if any, will be active credits
only to the extent of the converted Investor General Partner's regular federal
income tax liability which is allocable to his share of any net income of his
Partnership, which is still treated as non-passive income even after the
Investor General Partner has been converted to a Limited Partner. (See "-
Conversion from Investor General Partner to Limited Partner," above.) Any excess
credits
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Atlas Resources, Inc.
February 18, 2005
Page 24
allocable to the converted Investor General Partner, as well as all of the
marginal well production credits allocable to those investors who originally
invest in a Partnership as Limited Partners, will be passive credits which can
reduce only an investor's regular income tax liability attributable to passive
income from the Partnership or other passive activities.
DEPRECIATION - MODIFIED ACCELERATED COST RECOVERY SYSTEM ("MACRS").
Tangible Costs and the related depreciation deductions of each Partnership are
charged and allocated under the Partnership Agreement 66% to the Managing
General Partner and 34% to the Participants in the Partnership. However, if the
total Tangible Costs for all of the Partnership's wells that would otherwise be
charged to the Participants exceeds an amount equal to 10% of the Partnership's
subscription proceeds, then the excess Tangible Costs, together with the related
depreciation deductions, will be charged and allocated to the Managing General
Partner.
Each Partnership's reasonable costs for equipment placed in its
respective wells which cannot be deducted immediately ("Tangible Costs") will be
recovered through depreciation deductions over a seven year cost recovery period
using the 200% declining balance method, with a switch to straight-line to
maximize the deduction, beginning in the taxable year each well is drilled,
completed and made capable of production, i.e. placed in service by the
Partnership. I.R.C. Section 168(c). In the case of a short tax year the MACRS
deduction is prorated on a 12-month basis. No distinction is made between new
and used property and salvage value is disregarded. Under Section 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 Section 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 of these cost recovery deductions claimed by the Partnerships and their
respective Participants are subject to recapture as ordinary income rather than
capital gain on the sale or other taxable disposition of the property or a
Participant's Units. (See "- Sale of the Properties" and "- Disposition of
Units," below.) Depreciation for alternative minimum tax purposes is computed
using the 150% declining balance method, switching to straight-line, for most
personal property. This means that a Partnership's depreciation deductions in
its early years for alternative minimum tax purposes will be less than the
Partnership's depreciation deductions in those years for regular tax purposes,
and greater in the Partnership's later years. This will result in adjustments in
computing the alternative minimum taxable income of each of the Partnership's
Participants. (See "- Alternative Minimum Tax," below.)
A Participant's ability to use the Participant's share of these
deductions on the Participant's personal federal income tax returns may be
reduced, eliminated or deferred by the "Potential Limitations on Deductions" set
forth in opinion (4) in the "Opinions" section of this tax opinion letter above.
LEASE ACQUISITION COSTS AND ABANDONMENT. Lease acquisition costs,
together with the related cost depletion deduction and any abandonment loss for
Lease costs, are allocated under the Partnership Agreement 100% to the Managing
General Partner, which will contribute the Leases to each Partnership as a part
of its Capital Contribution.
TAX BASIS OF UNITS. A Participant's share of his Partnership's losses is
allowable only to the extent of the adjusted basis of his Units at the end of
the Partnership's taxable year. I.R.C. Section 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.
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Atlas Resources, Inc.
February 18, 2005
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The adjusted basis of a Participant's Units will be reduced by his:
(i) share of Partnership losses;
(ii) share of Partnership expenditures that are not deductible in
computing its taxable income and are not properly chargeable to
capital account;
(iii) depletion deductions, but not below zero; and
(iv) cash distributions from the Partnership. I.R.C. Sections 705,
722 and 742.
The reduction in a Participant's share of Partnership liabilities, if
any, is considered a cash distribution to the Participant. Although Participants
will not be personally liable on any Partnership loans, Investor General
Partners will be liable for other obligations of the Partnership. (See "Risk
Factors - Risks Related to an Investment In a Partnership - If You Choose to
Invest as a General Partner, Then You Have Greater Risk Than a Limited Partner"
in the Prospectus.) Should cash distributions to a Participant from his
Partnership exceed the tax basis of the Participant's Units, taxable gain would
result to the Participant to the extent of the excess. (See "- Distributions
From a Partnership," below.)
"AT RISK" LIMITATION FOR LOSSES. Subject to the limitations on "passive
losses" generated by a Partnership in the case of Limited Partners, a
Participant's particular alternative minimum tax situation, and a Participant's
basis in his Units, each Participant may use his share of the Partnership's
losses to offset income from other sources. (See "- Limitations on Passive
Activity Losses and Credits" and "- Tax Basis of Units," above, and "-
Alternative Minimum Tax," below.) However, 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 own more
than 50% (in value) of the outstanding stock as set forth in Section 542(a)(2)
of the Code, who sustains a loss in connection with a Partnership's natural gas
and oil activities may deduct the loss only to the extent of the amount he has
"at risk" in the Partnership at the end of a taxable year. I.R.C. Section 465.
(See "- Limitations on Passive Activity Losses and Credits," above, relating to
the application of Section 469 of the Code to closely held C corporations for
additional information on the stock ownership requirements of Section 542(a)(2)
of the Code. "Loss" means the excess of allowable deductions for a taxable year
from a Partnership over the amount of income actually received or accrued by the
Participant during the year from the Partnership.
A Participant's initial "at risk" amount is equal to the amount of money
he pays for his Units. However, any amounts borrowed by a Participant to buy his
Units will not be considered "at risk" if the amounts are borrowed from any
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 a Partnership may not include the amount
of any loss that the Participant is protected against through:
o nonrecourse loans;
o guarantees;
o stop loss agreements; or
o other similar arrangements.
The amount of any loss that is disallowed will be carried over to the next
taxable year, to the extent a Participant is "at risk" in the Partnership.
Further, a Participant's "at risk" amount in subsequent taxable years of the
Partnership will be reduced by that portion of the loss which is allowable as a
deduction.
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Atlas Resources, Inc.
February 18, 2005
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Since income, gains, losses, and distributions of the Partnership affect
the "at risk" amount, the extent to which a Participant is "at risk" must be
determined annually. Previously allowed losses must be included in gross income
if the "at risk" amount is reduced below zero. The amount included in income,
however, may be deducted in the next taxable year to the extent of any increase
in the amount which the Participant has "at risk" in the Partnership.
DISTRIBUTIONS FROM A PARTNERSHIP. 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.
Section 731(a)(1). Different rules apply, however, in the case of payments by a
Partnership to a deceased Participant's successor interest under Section 736 of
the Code and payments relating to unrealized receivables and inventory items
under Section 751 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 then only to the extent of
the excess, if any, of the Participants' adjusted basis in their Units over the
sum of the amount of money distributed to the Participants plus the
Participants' share of basis (as determined under Section 732 of the Code) of
any unrealized receivables (as defined in Section 751(c) of the Code) and
inventory (as defined in Section 751(d) of the Code) of their Partnership.
I.R.C. Section 731(a)(2). (See "- Disposition of Units," below, for a discussion
of unrealized receivables and inventory items under Section 751 of the Code.) No
gain or loss is recognized by the Partnership on these types of distributions.
I.R.C. Section 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. Sections 732, 733, 734,
and 754. (See Section 5.04(d) of the Partnership Agreement and "- Tax
Elections," below.) Other distributions of cash, disproportionate distributions
of property, if any, and liquidating distributions of a Partnership may result
in taxable gain or loss to its Participants. (See "- Termination of a
Partnership," below.)
SALE OF THE PROPERTIES. Under the Jobs and Growth Tax Relief
Reconciliation Act of 2003 ("2003 Tax Act"), the maximum tax rates on a
noncorporate taxpayer's adjusted net capital gain on the sale of assets held
more than a year of 20%, or 10% to the extent it would have been taxed at a 10%
or 15% rate if it had been ordinary income, have been reduced to 15% and 5%,
respectively, for most capital assets sold or exchanged after May 5, 2003. In
addition, for 2008 only, the 5% tax rate on adjusted net capital gain is reduced
to 0%. The 2003 Tax Act also eliminated the former maximum tax rates of 18% and
8%, respectively, on qualified five-year gain. I.R.C. Section 1(h). The new
capital gain rates also apply for purposes of the alternative minimum tax.
I.R.C. Section 55(b)(3). (See "- Alternative Minimum Tax," below.) However, the
former tax rates are scheduled to be reinstated January 1, 2009, as if the 2003
Tax Act had never been enacted. Under Section 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 Section 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 Section 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 (excess of
long-term gains over long-term losses) over net short-term capital loss (excess
of short-term gains over short-term losses). The annual capital loss limitation
for noncorporate taxpayers is the amount of capital gains plus the lesser of
$3,000, which is reduced to $1,500 for married persons filing separate returns,
or the excess of capital losses over capital gains. I.R.C. Section 1211(b).
Gains from sales of natural gas and oil properties held for more than 12
months will be treated as a long-term capital gain, while a net loss will be an
ordinary deduction, except to the extent of depreciation recapture on equipment
and recapture of Intangible Drilling Costs and depletion deductions as discussed
below. In addition, gain on the sale of a Partnership's natural gas and oil
properties may be recaptured as ordinary income to the extent of non-recaptured
Section 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. Section 1231(c). If, under Section 1231
of the Code, the Section 1231 gains for any taxable year exceed the Section 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 Section
1231 gains do not exceed the Section 1231 losses, the gains and losses will
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not be treated as gains and losses from sales or exchanges of capital assets.
For this purpose, the term "Section 1231 gain" means:
o any recognized gain on the sale or exchange of property used in
the trade or business; and
o any recognized gain from the involuntary conversion into other
property or money of:
o property used in the 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 "Section 1231 loss" means any recognized loss from a sale or exchange
or conversion described above.
The term "property used in the trade or business" means property used in the
trade or business of a character which is subject to the allowance for
depreciation and is held for more than one year, and real property which is used
in the trade or business and is held for more than one year, which is not:
o property which would properly be includable in inventory; or
o property held primarily for sale to customers in the ordinary
course of the trade or business.
The net Section 1231 gain will be treated as ordinary income to the extent
the gain does not exceed the non-recaptured net Section 1231 losses.
The term "non-recaptured net Section 1231 losses" means the excess of:
o the aggregate amount of the net Section 1231 losses for the five
most recent taxable years; over
o the portion of those losses taken into account to determine
whether the net Section 1231 gain for any taxable year should be
treated as ordinary income to the extent the gain does not
exceed the non-recaptured net Section 1231 losses, as discussed
above, for those preceding taxable years.
Other gains and losses on sales of natural gas and oil properties held
by the Partnership for less than 12 months, if any, will result in ordinary
gains or losses.
Intangible Drilling Costs and depletion allowances that are incurred in
connection with a natural gas or oil property may be recaptured as ordinary
income when the property is sold or otherwise disposed of in a taxable
transaction by a Partnership. The amount of gain recaptured as ordinary income
is the lesser of:
o the aggregate amount of expenditures which have been deducted as
Intangible Drilling Costs with respect to the property and
which, but for being deducted, would have been included in the
adjusted basis of the property, plus deductions for depletion
which reduced the adjusted basis of the property; or
o the excess of:
o the amount realized, in the case of a sale, exchange or
involuntary conversion; or
o the fair market value of the interest, in the case of
any other taxable disposition;
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over the adjusted basis of the property. I.R.C. Section
1254(a).
(See "- Intangible Drilling Costs" and "- Depletion Allowance," above.)
In addition, all gain on the sale or other taxable disposition of
equipment is treated as ordinary income to the extent of MACRS deductions
claimed by the Partnership. I.R.C. Section 1245(a). (See "- Depreciation -
Modified Accelerated Cost Recovery System ("MACRS"), above.)
DISPOSITION OF UNITS. The sale or exchange, including a purchase by the
Managing General Partner, of all or some of a Participant's Units held by him
for more than 12 months will result in a recognition by the Participant of
long-term capital gain or loss, except for previous deductions for depreciation,
depletion and Intangible Drilling Costs, and the Participant's share of the
Partnership's "Section 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, or services rendered or to be
rendered, to the extent not previously includable in income under the
Partnerships' accounting methods. I.R.C. Section 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. These tax items are sometimes referred to in this tax
opinion letter as "Section 751 assets." (See "- Sale of the Properties," above.)
If the 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. Therefore, the gain recognized by a
Participant may result in a tax liability to the Participant greater than the
cash proceeds, if any, received by the Participant from the disposition. In
addition to gain from a passive activity, a portion of any gain recognized by a
Limited Partner on the sale or other taxable disposition of his Units will be
characterized as portfolio income under Section 469 of the Code to the extent
the gain is attributable to portfolio income, e.g. interest income on
investments of working capital. Treas. Reg. Section 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.
Section 1031(a)(2)(D). Other dispositions of a Participant's Units may or may
not result in recognition of taxable gain. However, no gain should be recognized
by an Investor General Partner on the conversion of his Investor General Partner
Units to Limited Partner Units so long as there is no change in his share of his
Partnership's liabilities or Section 751 assets as a result of the conversion.
Rev. Rul. 84-52, 1984-1 C.B. 157.
A Participant who sells or exchanges all or some of his Units is
required by the Code to notify his Partnership within 30 days or by January 15
of the following year, if earlier. I.R.C. Section 6050K. After receiving the
notice, the Partnership is required to make a return with the IRS stating the
name and address of the transferor and the transferee, the fair market value of
the portion of the Partnership's unrealized receivables and appreciated
inventory allocable to the Units sold or exchanged (which is subject to
recapture as ordinary income instead of capital gain) and any other information
as may be required by the IRS. The Partnership must also provide each person
whose name is set forth in the return a written statement showing the
information set forth on the return.
If a Participant dies, or sells or exchanges all of his Units, the
taxable year of his Partnership will close with respect to that Participant, but
not the remaining Participants, on the date of death, sale or exchange, with a
proration of partnership items for the Partnership's taxable year. I.R.C.
Section 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
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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. Section
706(d).
Participants are urged to seek advice based on their particular
circumstances from an independent tax advisor before any disposition of a Unit,
including any purchase of the Unit by the Managing General Partner.
ALTERNATIVE MINIMUM TAX. With limited exceptions, taxpayers must pay an
alternative minimum tax if it exceeds the taxpayer's regular federal income tax
for the year. I.R.C. Section 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 for the regular tax treatment. A "preference" means the addition of the
difference between the alternative minimum tax treatment of a tax item and the
regular tax treatment. 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 for 2005 are $58,000 for married individuals filing jointly and
surviving spouses, $40,250 for single persons other than surviving spouses, and
$29,000 for married individuals filing separately. For years beginning after
2005, these exemption amounts are scheduled to decrease to $45,000 for married
individuals filing jointly and surviving spouses, $33,750 for single persons
other than surviving spouses, and $22,500 for married individuals filing
separately. The exemption amount for estates and trusts is $22,500 in 2005 and
subsequent years.
The exemption amounts set forth above are reduced by 25% of alternative
minimum taxable income in excess of:
o $150,000, in the case of married individuals filing a joint
return and surviving spouses - the $58,000 exemption amount is
completely phased out when alternative minimum taxable income is
$382,000 or more, and the $45,000 amount phases out completely
at $330,000;
o $112,500, in the case of unmarried individuals other than
surviving spouses - the $40,250 exemption amount is completely
phased out when alternative minimum taxable income is $273,500
or more, and the $33,750 amount phases out completely at
$247,500; and
o $75,000, in the case of married individuals filing a separate
return - the $29,000 exemption amount is completely phased out
when alternative minimum taxable income is $191,000 or more and
the $22,500 amount phases out completely at $165,000. In
addition, in 2005 the alternative minimum taxable income of
married individuals filing separately is increased by the lesser
of $29,000 ($22,500 after 2005) or 25% of the excess of the
person's alternative minimum taxable income (determined without
regard to this provision) over $191,000 ($165,000 after 2005).
Some of the principal adjustments to taxable income that are used to
determine alternative minimum taxable income include those summarized below:
o Depreciation deductions of the costs of the equipment in the
wells ("Tangible Costs") may not exceed deductions computed
using the 150% declining balance method. (See "- Depreciation -
Modified Accelerated Cost Recovery System ("MACRS")," above.)
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o Miscellaneous itemized deductions are not allowed.
o Medical expenses are deductible only to the extent they exceed
10% of adjusted gross income.
o State and local property taxes and income taxes (or sales taxes,
instead of state and local income taxes, at the taxpayer's
election in the 2005 taxable year), which are itemized and
deducted for regular tax purposes, are not deductible.
o Interest deductions are restricted.
o The standard deduction and personal exemptions are not allowed.
o Only some types of operating losses are deductible.
o Different rules under the Code apply to incentive stock options
that may require earlier recognition of income.
The principal tax preference items that must be added to taxable income
for alternative minimum tax purposes include:
o 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 Section 103 of the Code, excluding any qualified
Section 501(c)(3) bond (as defined in Section 145 of the Code).
Also, a "private activity bond" does not include any refunding
bond issued before August 8, 1986.
For taxpayers other than "integrated oil companies" as that term is defined in
"- Intangible Drilling Costs," above, which does not include the Partnerships,
the 1992 National Energy Bill repealed:
o the preference for excess Intangible Drilling Costs; and
o the excess percentage depletion preference for natural gas and
oil.
The repeal of the excess Intangible Drilling Costs preference, however, under
current law may not result in more than a 40% reduction in the amount of the
taxpayer's alternative minimum taxable income computed as if the excess
Intangible Drilling Costs preference had not been repealed. I.R.C.
Section 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 Section 59(e) of the Code to
capitalize all or part of his share of his Partnership's Intangible Drilling
Costs and deduct the costs ratably over a 60-month period beginning with the
month in which the costs
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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 tax deduction for Intangible Drilling
Costs in the year in which he invests will be reduced because
the Participant must spread the deduction for the amount of
Intangible Drilling Costs which the Participant elects to
capitalize over the 60-month amortization period; and
o the capitalized Intangible Drilling Costs will not be treated as
a preference that is included in the Participant's alternative
minimum taxable income.
Other than Intangible Drilling Costs as discussed above, the principal
tax item that may have an impact on a Participant's alternative minimum taxable
income as a result of investing in a Partnership is depreciation of the
Partnership's equipment expenses. As noted in "- Depreciation - Modified
Accelerated Cost Recovery System ("MACRS")," above, each Partnership's cost
recovery deductions for regular income tax purposes will be computed using the
200% declining balance method rather than the 150% declining balance method used
for alternative minimum tax purposes. This means that in the early years of a
Partnership a Participant's depreciation deductions from the Partnership 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 the Partnership's early years. Conversely,
this adjustment may decrease the Participant's alternative minimum taxable
income in the Partnership's later years.
A Participant's share of his Partnership's marginal well production
credits, if any, may not be used to reduce his alternative minimum tax
liability, if any. Also, the rules relating to the alternative minimum tax for
corporations are different from those summarized above. All prospective
Participants contemplating purchasing Units in a Partnership are urged to seek
advice based on their particular circumstances from an independent tax advisor
as to the likelihood of them incurring or increasing any alternative minimum tax
liability as a result of an investment in a Partnership.
LIMITATIONS ON DEDUCTION OF INVESTMENT INTEREST. Investment interest
expense is deductible by a noncorporate taxpayer only to the extent of net
investment income each year, with an indefinite carryforward of disallowed
investment interest. I.R.C. Section 163. Investment interest expense includes,
but is not limited to, all interest on debt which is allocable to property held
for investment and is not incurred in a person's active trade or business except
consumer interest, qualified residence interest, and passive activity interest
under Section 469 of the Code. Accordingly, an Investor General Partner's share
of any interest expense incurred by the Partnership in which he invests before
his Investor General Partner Units are converted to Limited Partner Units will
be subject to the investment interest limitation. I.R.C. Section
163(d)(5)(A)(ii). In addition, the Investor General Partner's share of the
Partnership's income and losses, including the deduction for Intangible Drilling
Costs, will be considered to be investment income and losses for purposes of
this limitation. Thus, for example, a loss allocated to an Investor General
Partner from the Partnership in the year in which he invests in the Partnership
as a result of the deduction for Intangible Drilling Costs will reduce his net
investment income and may reduce or eliminate the deductibility of his
investment interest expenses, if any, in that taxable year with the disallowed
portion to be carried forward to the next taxable year.
Net investment income is the excess of investment income over investment
expenses. Investment income includes:
o gross income from interest, rents, and royalties from property
held for investment;
o any excess of net gain from dispositions of investment property
over net capital gain determined by gains and losses from
dispositions of investment property, and any portion of the net
capital gain or net gain, if less, that the taxpayer elects to
include in investment income;
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o portfolio income under the passive activity rules, which
includes working capital investment income;
o dividends that do not qualify to be taxed at capital gain rates
and qualified dividend income that the taxpayer elects to treat
as investment income and not as income qualified to be taxed at
capital gain rates; and
o income from a trade or business in which the taxpayer does not
materially participate if the activity is not a "passive
activity" under Section 469 of the Code. In the case of Investor
General Partners, this includes the Partnership in which they
invest before the conversion of Investor General Partner Units
to Limited Partner Units in that Partnership, and possibly
Partnership net income allocable to former Investor General
Partners after they are converted to Limited Partners in that
Partnership.
Investment expenses include deductions, other than interest, that are directly
connected with the production of net investment income, including actual
depreciation or depletion deductions allowable. Investment income and investment
expenses, however, do not include a Partnership's income or expenses taken into
account in computing income or loss from a passive activity under Section 469 of
the Code. (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 than
allocations of other tax items. (See "Participation in Costs and Revenues" in
the Prospectus.) The Capital Accounts 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. 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 Section 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 income and gain to him from the Partnership;
and decreased by:
o the value of property or cash distributed to him by the
Partnership; and
o allocations of losses and deductions to him by the Partnership.
The regulations also require that there must be a reasonable possibility that
the allocation will affect substantially the dollar amounts to be received by
the partners from the partnership, independent of tax consequences.
Allocations made in a manner that is disproportionate to the respective
interests of the partners in a partnership of any item of partnership income,
gain, loss, deduction or credit will not be given effect unless the allocation
has "substantial economic effect." I.R.C. Section 704(b). 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
economic benefit or bear the 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,
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independent of tax consequences and taking into account the Participants' tax
attributes that are unrelated to the Partnership in which they invest. An
allocation will have economic effect if throughout the term of a partnership:
o the partners' capital accounts are increased and decreased as
described above;
o liquidation proceeds are distributed in accordance with the
partners' capital accounts; and
o any partner with a deficit balance in his capital account
following the liquidation of his interest in the partnership is
required to restore the amount of the deficit to the
partnership.
Even though the Participants in each Partnership are not required under
the Partnership Agreement to restore deficit balances in their Capital Accounts
with additional Capital Contributions, an allocation which is not attributable
to nonrecourse debt still will be considered under the regulations to have
economic effect to the extent it does not cause or increase a deficit balance in
a Participant's Capital Account if:
o the Partners' Capital Accounts are 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 income and gain sufficient to eliminate the deficit
balance as quickly as possible.
Treas. Reg. Section 1.704-l(b)(2)(ii)(d). These provisions are included in the
Partnership Agreement (See Sections 5.02, 5.03(h), and 7.02(a) of the
Partnership Agreement.)
Special provisions apply to deductions related to nonrecourse debt and
tax credits, since allocations of these items cannot have substantial economic
effect . If the Managing General Partner or an Affiliate makes a nonrecourse
loan to a Partnership ("partner nonrecourse liability"), Partnership losses,
deductions, or Section 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 Sections 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
Section 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 adjustments to a Partnership's properties.)
It should also be noted that each Participant's share of items of
income, gain, loss, deduction and credit in the Partnership in which he invests
must be taken into account by him whether or not he receives any cash
distributions from the Partnership. For example, a Participant's share of
Partnership revenues applied by his Partnership to the repayment of loans or the
reserve for plugging wells will be included in his gross income in a manner
analogous to an actual distribution
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of the revenues (and income) to him. Thus, a Participant may have tax liability
on taxable income from his Partnership for a particular year in excess of any
cash distributions from the Partnership to him with respect to that year. To the
extent a Partnership has cash available for distribution, however, it is the
Managing General Partner's policy that the Partnership's cash distributions to
its Participants will not be less than the Managing General Partner's estimate
of the Participants' income tax liability with respect to that Partnership's
income.
If any allocation under the Partnership Agreement is not recognized for
federal income tax purposes, each Participant's share of the items subject to
the allocation will be determined in accordance with his interest in the
Partnership in which he invests by considering all of the relevant facts and
circumstances. To the extent deductions or credits allocated by the Partnership
Agreement exceed deductions or credits which would be allowed under a
reallocation by the IRS, Participants may incur a greater tax burden.
PARTNERSHIP BORROWINGS. Under the Partnership Agreement the Managing
General Partner and its Affiliates may make loans to the Partnerships. The use
of Partnership revenues taxable to Participants to repay borrowings by their
Partnership could create income tax liability for the Participants in excess of
their cash distributions from the Partnership, since repayments of principal are
not deductible for federal income tax purposes. In addition, interest on the
loans will not be deductible unless the loans are bona fide loans that will not
be treated as Capital Contributions to the Partnership by the Managing General
Partner or its Affiliates in light of all of the surrounding facts and
circumstances. In Revenue Ruling 72-135, 1972-1 C.B. 200, the IRS ruled that a
nonrecourse loan from a general partner to a partnership engaged in natural gas
and oil exploration represented a capital contribution by the general partner
rather than a loan. Whether a "loan" by the Managing General Partner or its
Affiliates to a Partnership represents in substance debt or equity is a question
of fact to be determined from all the surrounding facts and circumstances.
PARTNERSHIP ORGANIZATION AND OFFERING COSTS. Expenses connected with the
offer and sale of Units in a Partnership, such as promotional expense, the
Dealer-Manager fee, Sales Commissions, reimbursements to the Dealer-Manager and
other selling expenses, professional fees, and printing costs, which are charged
under the Partnership Agreement 100% to the Managing General Partner as
Organization and Offering Costs, are not deductible. Although expenses incident
to the creation of a partnership may be amortized over a period of not less than
180 months, these expenses also will be paid by the Managing General Partner as
part of each Partnership's Organization and Offering Costs. Thus, any related
deductions, which the Managing General Partner does not anticipate will be
material in amount as compared to the total subscription proceeds of the
Partnerships, will be allocated to the Managing General Partner. I.R.C. Section
709; Treas. Reg. Sections 1.709-1 and 2.
TAX ELECTIONS. Each Partnership may elect to adjust the basis of its
property (other than cash) on the transfer of a Unit in the Partnership by sale
or exchange or on the death of a Participant, and on the distribution of
property by the Partnership to a Participant (the Section 754 election). If the
Section 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 has represented that due to
the complexities and added expense of the tax accounting required to implement a
Section 754 election to adjust the basis of a Partnership's property when Units
are sold, taking into account the limitations on the sale of the Partnership's
Units, neither Partnership will make the Section 754 election. Even though the
Partnerships will not make the Section 754 election, the basis adjustment
described above is mandatory under the Code with respect to the transferee
Partner only, if at the time a Unit is transferred by sale or exchange, or on
the death of a Participant, the Partnership's adjusted basis in its property
exceeds the fair market value of the property by more than $250,000 immediately
after the transfer of the Unit. Similarly, a basis adjustment is mandatory under
the Code if a partnership distributes property in-kind to a partner,
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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. Sections 734 and 743. In
this regard, under Section 7.02(c) of the Partnership Agreement a Partnership
will not distribute its assets in-kind to its Participants, except to a
liquidating trust or similar entity for the benefit of its Participants, unless
at the time of the distribution the Participants have been offered the election
of receiving in-kind property distributions, and any Participant accepts the
offer after being advised of the risks associated with direct ownership; or
there are alternative arrangements in place which assure the Participants that
they will not, at any time, be responsible for the operation or disposition of
the Partnership's properties.
If the basis of a Partnership's assets must be adjusted as discussed
above, the primary effect on the Partnership, other than the federal income tax
consequences discussed above, would be an increase in its administrative and
accounting expenses to make the required basis adjustments to its properties and
separately account for those adjustments after they are made. In this regard,
the Partnerships will not make in-kind property distributions to their
respective Participants except in the limited circumstances described above, and
the Units have no readily available market and are subject to substantial
restrictions on their transfer. (See "Transferability of Units - Restrictions on
Transfer Imposed by the Securities Laws, the Tax Laws and the Partnership
Agreement" in the Prospectus.) These factors will tend to limit the additional
expense to a Partnership if the mandatory basis adjustments to a Partnership's
assets described above apply to it. In addition to the Section 754 election,
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.
Code Section 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 as the
trade or business referred to above), 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 would be amortized over the
180-month period.
TERMINATION OF A PARTNERSHIP. Under Section 708(b) of the Code, a
Partnership will be considered as terminated for federal income tax purposes if
within a 12-month period there is a sale or exchange of 50% or more of the total
interest in Partnership capital and profits. The closing of the Partnership year
may result in more than 12 months' income or loss of the Partnership being
allocated to Participants which use a fiscal year other than the calendar year.
Under Section 731 of the Code, a Participant will realize taxable gain on a
termination of a Partnership to the extent that money regarded as distributed to
him by the Partnership exceeds the adjusted basis of his Units. The conversion
of Investor General Partner Units to Limited Partner Units, however, will not
terminate a Partnership. Rev. Rul. 84-52, 1984-1 C.B. 157. Also, due to
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the restrictions on transfers of Units in the Partnership Agreement, the
Managing General Partner does not anticipate that either Partnership will ever
be considered as terminated under Section 708(b) of the Code.
TAX RETURNS AND IRS AUDITS. The tax treatment of most partnership items
is determined at the partnership, rather than the partner, level. Also, the
partners are required to treat partnership items on their individual federal
income tax returns in a manner which is consistent with the treatment of the
partnership items on the partnership's federal information income tax return
unless they disclose to the IRS, by attaching to their personal federal income
tax returns IRS Form 8082 "Notice of Inconsistent Treatment or Administrative
Adjustment Request (AAR)," that their tax treatment of Partnership tax items on
their personal federal income tax return is different from their Partnership's
tax treatment of those items. I.R.C. Sections 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. Section 301.6231(a)(3)-1.
The IRS must conduct an administrative determination as to partnership
items at the partnership level before conducting deficiency proceedings against
a partner, and the partners must file a request for an administrative
determination before filing suit for any credit or refund. The period for
assessing tax against the Participants attributable to a partnership item may be
extended by agreement between the IRS and the Managing General Partner, which
will serve as each Partnership's representative ("Tax Matters Partner") in all
administrative tax proceedings or tax litigation conducted at the partnership
level. The Tax Matters Partner may enter into a settlement on behalf of, and
binding on, any Participant owning less than a 1% profits interest in a
Partnership if there are more than 100 partners in the Partnership, unless that
investor 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 investor. Based on its past experience,
the Managing General Partner anticipates that there will be more than 100
partners in each of the Partnerships, if Units in Atlas America Public
#14-2005(B) L.P. are offered. By executing the Partnership Agreement, each
Participant agrees that he will not form or exercise any right as a member of a
notice group and will not file a statement notifying the IRS that the Tax
Matters Partner does not have binding settlement authority. In addition, a
partnership with at least 100 partners may elect to be governed under simplified
tax reporting and audit rules as an "electing large partnership." I.R.C. Section
775. These rules would help the IRS match partnership items with the
Participants' personal federal income tax returns. In addition, most limitations
affecting the calculation of the taxable income and tax credits of an electing
large partnership are applied at the partnership level and not the partner
level. Thus, the Managing General Partner does not anticipate that either
Partnership will make this election.
All expenses of any 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 adjustments made by the IRS. The Managing General Partner
will notify the Participants of any IRS audits or other tax proceedings
involving their Partnership, and will provide the Participants any other
information regarding the proceedings as may be required by the Partnership
Agreement or law.
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 Section 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
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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 Section 183
of the Code. (See Treas. Reg. Section 1.183-2(c), Example (5).)
Under Treas. Reg. Section 1.701-2, if a principal purpose of a
partnership is to reduce substantially the partners' federal income tax
liability in a manner that is inconsistent with the intent of the partnership
rules of the Code, based on all the facts and circumstances, the IRS is
authorized to remedy the abuse. For illustration purposes, the following factors
may indicate that a partnership is being used in a prohibited manner:
o the partners' aggregate federal income tax liability is
substantially less than had the partners owned the partnership's
assets and conducted its activities directly;
o the partners' aggregate federal income tax liability is
substantially less than if purportedly separate transactions are
treated as steps in a single transaction;
o one or more partners are needed to achieve the claimed tax
results and have a nominal interest in the partnership or are
substantially protected against risk; and
o income or gain are allocated to partners who are not expected to
have any federal income tax liability.
We also have considered the possible application to each Partnership and
its intended activities of the potentially relevant judicial doctrines
summarized below.
o Step Transactions. This doctrine provides that where a series of
transactions would give one tax result if viewed independently,
but a different tax result if viewed together, then the IRS may
combine the separate transactions.
o Business Purpose. This doctrine involves a determination of
whether the taxpayer has a business purpose, other than tax
avoidance, for engaging in the transaction, i.e. a "profit
objective."
o Economic Substance. This doctrine requires a determination of
whether, from an objective viewpoint, a transaction is likely to
produce economic benefits in addition to tax benefits. This test
is met if there is a realistic potential for profit when the
investment is made, in accordance with the standards applicable
to the relevant industry, so that a reasonable businessman,
using those standards, would make the investment.
o Substance Over Form. This doctrine holds that the substance of
the transaction, rather than the form in which it is cast,
governs. It applies where the taxpayer seeks to characterize a
transaction as one thing, rather than another thing which has
different tax results. Under this doctrine, the transaction must
have practical economical benefits other than the creation of
income tax losses.
o Sham Transactions. Under this doctrine, a transaction lacking
economic substance may be ignored for tax purposes. Economic
substance requires that there be business realities and
tax-independent considerations, rather than just tax-avoidance
features, i.e. the transaction must have a reasonable and
objective possibility of providing a profit aside from tax
benefits. Shams include, for example, transactions entered into
solely to reduce taxes, which is not a profit motive because
there is no intent to produce taxable income.
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In our opinion, the Partnerships will possess the requisite profit
motive under Section 183 of the Code, and the IRS anti-abuse rule in Treas. Reg.
Section 1.701-2 and the potentially relevant judicial doctrines summarized above
will not have a material adverse effect on the tax consequences of an investment
in a Partnership by a typical Participant as described in our opinions. These
opinions are based in part on:
o the results of the previous partnerships sponsored by the
Managing General Partner as set forth in "Prior Activities" in
the Prospectus; and
o the Managing General Partner's representations, which include
representations that:
o each Partnership will be operated as described in the
Prospectus (see "Management" and "Proposed Activities"
in the Prospectus); and
o the principal purpose of each Partnership is to locate,
produce and market natural gas and oil on a profitable
basis, apart from tax benefits, as described in the
Prospectus.
The Managing General Partner's representations are supported by the geological
evaluations and the other information for the Partnerships' proposed drilling
areas, and the specific Prospects proposed to be drilled by Atlas America Public
#14-2005(A) L.P. included in Appendix A to the Prospectus. Also, the Managing
General Partner has represented that Appendix A in the Prospectus will be
supplemented or amended to cover a portion of the specific Prospects proposed to
be drilled by Atlas America Public #14-2005(B) L.P. when Units in that
Partnership are first offered to prospective Participants.
FEDERAL INTEREST AND TAX PENALTIES. Taxpayers must pay tax and interest
on underpayments of federal income taxes and the Code contains various
penalties, including a penalty equal to 20% of the amount of a substantial
understatement of federal income tax liability. An understatement occurs if the
correct income tax, as finally determined, exceeds the income tax liability
actually shown on the taxpayer's federal income tax return. An understatement on
a non-corporate taxpayer's federal income tax return is substantial if it
exceeds the greater of 10% of the correct tax, or $5,000. In the case of a
corporation, other than an S corporation or a personal holding company, an
understatement is substantial if it exceeds the lesser of: (i) 10% of the tax
required to be shown on the return for the tax year (or, if greater, $10,000);
or (ii) $10 million). I.R.C. Section 6662. A taxpayer may avoid this penalty if
the understatement was not attributable to a "tax shelter," and there was
substantial authority for the taxpayer's tax treatment of the item that caused
the understatement, or if the relevant facts were adequately disclosed on the
taxpayer's tax return and the taxpayer had a "reasonable basis" for the tax
treatment of that item. In the case of an understatement that is attributable to
a "tax shelter," however, which may include each of the Partnerships for this
purpose, the penalty may be avoided only if there was reasonable cause for the
underpayment and the taxpayer acted in good faith, or there is or was
substantial authority for the taxpayer's treatment of the item, and the taxpayer
reasonably believed that his or her treatment of the item on the tax return was
more likely than not the proper treatment.
For purposes of this penalty, the term "tax shelter" includes a
partnership if a "significant" purpose of the partnership is the avoidance or
evasion of federal income tax. In this regard, each Partnership anticipates
incurring tax Losses during at least its first year when it pays (or prepays)
the Participants' share of the costs of drilling its wells. Before the Code was
amended in 1997, a partnership was defined as a tax shelter for purposes of
Section 6662 of the Code if its "principal" purpose, rather than a "significant"
purpose as the Code currently provides, was to avoid or evade federal income
tax. Treas. Reg. Section 1.6662-4(g)(2)(ii), which has not been updated to
reflect the 1997 amendment to Section 6662 discussed above, states:
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"The principal purpose of an entity, plan or arrangement is not to avoid
or evade Federal income tax if the entity, plan or arrangement has as
its purpose the claiming of exclusions from income, accelerated
deductions or other tax benefits in a manner consistent with the statute
and Congressional purpose. ..."
As noted above, the 1997 amendment to Section 6662 of the Code changed
the "principal" purpose to a "significant" purpose in the definition of a tax
shelter for purposes of Section 6662. In our view, this amendment changed only
the degree of the taxpayer's purpose (i.e. previously a principal purpose that
exceeds any other purpose, as compared with the current requirement of only a
significant purpose, which is one of two or more significant purposes).
Accordingly, it would appear that neither Partnership should be treated as a
"tax shelter" for purposes of Section 6662 of the Code if it incurs tax losses
in accordance with standard commercial business practices as described in the
Prospectus, and properly claims tax benefits under the Code, such as, for
example, the deduction of Intangible Drilling Costs under Section 263(c) and
Treas. Reg. Section 1.612-4(a); the deduction of ordinary, reasonable and
necessary business expenses under Section 162 of the Code; and accelerated
depreciation deductions on the Tangible Costs of its wells under Section 168 of
the Code; in "a manner consistent with" the Code and Congressional purpose as
set forth in Treas. Reg. Section 1.6662-4(g)(2)(ii). On the other hand, if a
Partnership's tax treatment of its intended activities were to actually result
in a substantial understatement of the correct amount of federal income taxes on
its Participants' personal federal income tax returns, the IRS could argue,
based on the facts and circumstances at that time, that the Partnership
improperly claimed the tax benefits for the purpose of avoiding federal income
taxes and should, therefore, be treated as a tax shelter for purposes of this
penalty. Due to the many inherently factual determinations involved, we are
unable to express an opinion on this issue.
In addition, under Section 6662A of the Code there is a 20% penalty for
reportable transaction understatements for any tax year. If the disclosure rules
for reportable transactions are not met, then this penalty is increased from 20%
to 30%, and the "reasonable cause" exception to the penalty, which is discussed
below, will not be available. A reportable transaction understatement is:
o the amount of the increase (if any) in taxable income resulting
from the proper tax treatment of a tax item subject to this
rule, as discussed below, instead of the taxpayer's treatment of
the tax item on the taxpayer's tax return, multiplied by the
highest noncorporate income tax rate (or corporate income tax
rate, in the case of a corporation); and
o the amount of the decrease (if any) in the aggregate amount of
credits resulting from a difference between the taxpayer's
treatment of a tax item subject to this rule, as discussed
below, and the proper tax treatment.
A tax item is subject to the reportable transaction understatement rules if the
tax item is attributable to:
o any listed transaction; and
o any other reportable transaction (other than a listed
transaction) if a significant purpose of the transaction is
federal income tax avoidance or evasion.
As set forth above, even if a Partnership is a reportable transaction
(other than a listed transaction), the penalty does not apply if the Partnership
does not have a significant purpose to avoid or evade federal income taxes. See
the discussion above concerning special counsel's inability to express an
opinion with respect to this issue. In our opinion, it is more likely than not
that the Partnerships will not be treated as reportable transactions under
Section 6707A of the Code and Treas. Reg. Section 1.6011-4(b). The types of
transactions which are treated as reportable transactions under the Code are
summarized below. This opinion is based in part on the Managing General
Partner's representation, which we believe is
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reasonable in light of the Partnerships' intended activities as described in the
Prospectus, that each Partnership's total abandonment losses under Section 165
of the Code, which could include, for example:
o the abandonment by a Partnership of wells drilled which are
nonproductive (i.e. a "dry hole"), in which case the Intangible
Drilling Costs, the Tangible Costs, and possibly the Lease costs
of the abandoned wells would be deducted as Section 165 losses;
or
o wells which have been operated until their commercial natural
gas and oil reserves have been depleted, in which case the
undepreciated Tangible Costs, possibly the Lease costs, and any
Intangible Drilling Costs which have not previously been
deducted (all of a Participant's Intangible Drilling Costs may
not have been deducted if the Participant elected to amortize
all or a portion of the Participant's share of the Partnership's
Intangible Drilling Costs over a 60-month period as discussed in
"- Alternative Minimum Tax," above, and the well is abandoned
within that 60-month period), would be deducted as Section 165
losses;
(and each Participant's allocable share of those abandonment losses), will be
less than $2 million in any taxable year of a Partnership and less than an
aggregate total of $4 million during the Partnership's first six taxable years.
The IRS, however, may at any time in its discretion publicly decide that
natural gas and oil drilling programs such as the Partnerships should be "listed
transactions," which is one type of reportable transaction summarized below.
Being a reportable transaction would increase the risk that a Partnership's
federal information income tax returns and the personal federal income tax
returns of its Participants would be audited by the IRS. In this regard,
however, merely being designated as a reportable transaction has no legal effect
on whether the tax treatment of any transaction by a Partnership or its
Participants for federal tax purposes was proper or improper. However, the
obligation of a Partnership's material advisors and the Partnership's
Participants to disclose the Partnership to the IRS as a reportable transaction,
if the Partnership is determined to be a reportable transaction in the future,
will apply whether or not there actually is a reportable transaction
understatement of federal income tax. The Partnerships' material advisors
include the Managing General Partner, Affiliates of the Managing General
Partner, and third-parties, such as us, who have participated in creating,
documenting, marketing or otherwise implementing this offering of Units in the
Partnerships. There are also significant penalties for failing to properly
disclose a reportable transaction, as discussed below.
Under Section 6707A of the Code and Treas. Reg. Section 1.6011-4(b),
there are six categories of reportable transactions, which are summarized below.
(1) A listed transaction is the same as, or substantially similar
to, a transaction that the IRS has publicly determined is a tax
avoidance transaction. Because the determination of what
additional transactions will be listed transactions is in the
sole discretion of the IRS, there is always a possibility that
the IRS could determine in the future that natural gas and oil
drilling programs such as the Partnerships should be listed
transactions, and therefore, must be treated as reportable
transactions.
(2) A confidential transaction includes an investment in which the
investors' rights to disclose the tax treatment or tax structure
of the investment are limited in order to protect the
confidentiality of the tax strategies of the investment, and the
person offering the investment is paid a fee of $50,000 or more
by the investors for his or her tax services or strategies. The
Partnerships are not confidential transactions, because they
have no limitations on the disclosure of their tax treatment or
tax structure.
(3) A transaction with contractual protection is a transaction in
which an investor has the right to a refund of a portion or all
of his investment or any fees paid by him in connection with the
transaction, if all or part of the intended tax consequences
from the transaction ultimately are not sustained, or if a
portion or all of his investment or any fees or other charges to
be paid by the investor are contingent on the investor's
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realization of tax benefits from the transaction. In this
regard, the Partnerships are not transactions with contractual
protection, because no one, including the Managing General
Partner, its Affiliates, or the Partnership, provides any
contractual protection to the Participants against the
possibility that part or all of the intended tax consequences or
tax benefits of an investment in a Partnership by a Participant
will be disallowed by the IRS. For example, the Managing General
Partner, its Affiliates and the Partnerships provide no
insurance, tax indemnity or similar agreement for the tax
treatment of a Participant's investment in a Partnership, and a
Participant has no right to rescind or receive a refund of any
of the Participant's investment in the Partnership or any fees
paid by the Partnership to the Managing General Partner, its
Affiliates or independent third-parties, including us, if any
intended tax consequences of the Participant's investment in a
Partnership ultimately are not sustained if challenged by the
IRS. None of these fees or payments is contingent on whether the
intended tax consequences or tax benefits of a Partnership are
ultimately sustained.
(4) A loss transaction under Treas. Reg. Section 1.6011-4(b)(5)
includes any investment resulting in a partnership which has
non-corporate partners, or any non-corporate partner, claiming a
loss under Section 165 of the Code of at least $2 million in any
single taxable year or $4 million in aggregate Section 165
losses in the taxable year that the investment is entered into
and the five succeeding taxable years combined. This means that
a Participant in a Partnership, if the Partnership is determined
to be a reportable transaction because the Partnership's Section
165 losses have met the dollar thresholds set forth above, is
still not required to file an IRS Form 8886 "Reportable
Transaction Disclosure Statement" with the Participant's
personal federal income tax return, and the Participant is not
personally subject to the substantial penalties for failing to
disclose the Partnership to the IRS as a reportable transaction
as discussed below, so long as the Participant's share of the
Partnership's Section 165 losses do not exceed:
o $2 million on his Schedule K-1 in any taxable year of
his Partnership; or
o $4 million, in the aggregate, in any combination of
taxable years of his Partnership during his
Partnership's first six taxable years;
on his Schedule K-1 from his Partnership in each taxable year he
is a Participant in the Partnership.
For this purpose, a Section 165 loss includes an amount
deductible under a provision of the Code that treats a
transaction as a sale or other disposition, or otherwise results
in a deduction under Section 165. A Section 165 loss includes,
for example, a loss resulting from a sale or exchange of a
partnership interest. The amount of a Section 165 loss is
adjusted for any salvage value and for any insurance or other
compensation received. However, a Section 165 loss for this
purpose does not take into account offsetting gains, or other
income limitations.
In this regard, each Partnership anticipates incurring a tax
Loss during at least its first year, due primarily to the amount
of Intangible Drilling Costs it intends to claim as a deduction
as described in the "Material Federal Income Tax Consequences -
Summary Discussion of the Material Federal Income Tax
Consequences of an Investment in a Partnership - Drilling
Contracts" section of the Prospectus. The Managing General
Partner anticipates that each Partnership's Loss in its first
taxable year will be in an amount greater than $2 million, with
the actual amount of the Loss of each Partnership depending
primarily on the amount of the Partnership's subscription
proceeds. In our opinion, however, it is more likely than not
that Losses claimed by a Partnership which result from
deductions claimed by the Partnership for Intangible Drilling
Costs of productive wells (other than any remaining Intangible
Drilling Costs of a well which is abandoned if a Participant has
elected to amortize the Participant's share of the Intangible
Drilling Costs of that well) should not be treated as Section
165 losses under the Code
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for purposes of the reportable transactions rules under the Code
and the Treasury Regulations. In this regard, IRS Revenue
Procedure 2003-24, 2003-11 C.B. 599, describes losses under
Section 165 of the Code which will not be taken into account in
determining whether a transaction is a loss transaction under
Treas. Reg. Section 1.6011-4(b)(5) as described above,
including:
"...A loss that is equal to, and is determined solely by the
reference to, a payment of cash by the taxpayer (for example, a
cash payment by a guarantor that results in a loss or a cash
payment that is treated as a loss from the sale of a capital
asset under Section 1234A or Section 1234B."
This provision of the Revenue Procedure tends to support the
position that a loss resulting from the deduction of Intangible
Drilling Costs should not be treated as a loss under Section 165
of the Code for purposes of determining whether a Partnership is
a reportable transaction. For example, it could be argued that
the loss resulting from the deduction for Intangible Drilling
Costs is a loss that is equal to, and determined solely by, the
Partnership's cash payment of Intangible Drilling Costs to the
Managing General Partner, acting as general drilling contractor.
On the other hand, the examples of the excluded losses set forth
in the language quoted above from the Revenue Procedure do not
specifically include a loss resulting from a deduction of
Intangible Drilling Costs as an example of an excluded loss.
This may be because the deduction for Intangible Drilling Costs
is not a deductible loss under Section 165 at all, but is
deductible under Section 263(c) of the Code and Treas. Reg.
Section 1.612-4(a), and therefore is irrelevant with respect to
Section 165 of the Code, or it may be because the deduction of
Intangible Drilling Costs is intended by the IRS to be included
in Section 165 losses which are taken into account in
determining whether a loss transaction is a reportable
transaction under the Revenue Procedure, but is simply not
mentioned by the IRS in the Revenue Procedure. This lack of
substantial authority with respect to this issue creates some
doubt as to the proper federal tax treatment of a Loss resulting
from the deduction of Intangible Drilling Costs for purposes of
determining whether a Partnership is a reportable transaction
under Treas. Reg. Section 1.6011-4(b)(5). Therefore, our
opinions expressed above with respect to these issues are "more
likely than not" opinions.
Also, if a Partnership drills a "dry hole" i.e. a well which is
nonproductive, or plugs and abandons a productive well after its
commercial natural gas and oil reserves have been produced and
depleted, which in the case of the wells to be drilled by the
Partnerships the Managing General Partner has represented is
likely to be many years after the well was drilled, then the
Partnership will abandon the well and claim a loss under Section
165 of the Code in the amount of its remaining basis in the well
and perhaps the Prospect which includes the well. The
Partnership's remaining basis in the abandoned well and Prospect
may consist of, for example, leasehold acquisition expenses not
previously recovered through the depletion allowance or the cost
of unsalvageable equipment that has not previously been
recovered through depreciation deductions. (See " - Lease
Acquisition Costs and Abandonment," above.) The Intangible
Drilling Costs of the well, however, would previously have been
expensed by the Partnership, since the Managing General Partner
has represented that each Partnership will make the election
under Section 263(c) of the Code and Treas. Reg. Section
1.612-4(a) to expense, rather than capitalize, the Intangible
Drilling Costs of all of its wells. In the case of a
Participant, however, the abandonment loss may include the
Participant's unamortized allocable share of the Partnership's
Intangible Drilling Costs if the Participant elected to amortize
those costs over 60 months. In this regard, however, the
Managing General Partner has represented that it believes that
each productive well drilled by a Partnership will produce for
more than five years. Therefore, although possible, it is not
likely that a Participant's share of the abandonment losses of
the Partnership in which the Participant invests will include
any portion of the Participant's share of the Partnership's
Intangible Drilling Costs. Thus, the Managing General
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Partner has represented that although possible, it does not
anticipate that either Partnership's abandonment loss claims
under Section 165 of the Code for its dry holes, if any, or
depleted wells, will ever total $2 million or more in losses in
any single taxable year, or $4 million or more in total
aggregate losses in the Partnership's first six years after the
wells are drilled, which are the thresholds which would cause a
Partnership to be a loss transaction which is treated as a
reportable transaction under Treas. Reg. Section 1.6011-4(b)(5)
as described above.
(5) A transaction which has a significant book-tax difference is a
reportable transaction if the amount for tax purposes of any
item or items of income, gain, expense, or loss from the
investment differs by more than $10 million on a gross basis
from the amount of the item or items for book purposes in any
taxable year. This provision does not apply to Participants in
the Partnerships who are natural persons, but does apply to
taxpayers that are reporting companies under the Securities
Exchange Act of 1934 which may include the Partnerships. In this
regard, IRS Revenue Procedure 2003-25, 2003-11CB 601, provides,
among other things, that book-tax differences arising from
percentage depletion under Sections 613 or 613A of the Code;
Intangible Drilling Costs deductible under Section 263(c) of the
Code; and depreciation and amortization relating solely to
differences in methods, useful lives or recovery periods,
conventions, etc., are not taken into account in determining
whether a transaction has a significant book-tax difference for
this purpose. Thus, the Managing General Partner has represented
that it does not anticipate that the Partnerships will have a
significant book-tax difference for this purpose in any of their
taxable years.
(6) A transaction involving a brief asset holding period is any
investment resulting in an investor claiming a tax credit
exceeding $250,000 if the underlying asset giving rise to the
credit is held by the taxpayer for 45 days or less. Under
current tax laws this type of reportable transaction should not
include the Partnerships, because no productive well of a
Partnership which may generate marginal well production tax
credits as discussed in "- Marginal Well Production Credits,"
above, will be held by the Partnership for 45 days or less. In
addition, even if all of the Partnerships' wells were taken into
account (which the Managing General Partner anticipates would be
approximately 407 wells as set forth in the Prospectus), the
Managing General Partner believes that any marginal well
production credits arising from the natural gas and oil
production for that short period of time would not exceed
$250,000.
The reportable transaction understatement penalty is not imposed if the
taxpayer shows that there was a reasonable cause for the understatement and that
the taxpayer acted in good faith. However, this exception to the penalty does
not apply to any reportable transaction understatement unless:
o the tax treatment of the item is adequately disclosed to the
IRS;
o there is or was substantial authority for the tax treatment; and
o the taxpayer reasonably believed that its tax treatment was more
likely than not the proper treatment.
Under Section 6664(d)(3)(B)(ii) of the Code, our tax opinion letter
cannot be relied on by the Participants in either Partnership to establish their
"reasonable belief" for purposes of this exception to the penalty, because we
have been compensated directly by the Managing General Partner for providing
this tax opinion letter and helping organize and document the offering.
Therefore, if the situation ever arises, a Partnership's Participants must
establish their "reasonable belief" for this purpose by some means other than
this tax opinion letter. See " - Disclosures and Limitation on Investors' Use of
Our Tax Opinion Letter," above.
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Also, under Section 7525 of the Code, written communications with
respect to tax shelters are not subject to the confidentiality provision that
otherwise applies to communications between a taxpayer and a federally
authorized tax practitioner, such as a certified public accountant. The term
"tax shelter" for purposes of this rule, includes a partnership if it has a
significant purpose of avoiding or evading income tax. In this regard, see the
discussion of the substantial understatement of income tax penalty above.
In addition, under Sections 6111 and 6112 of the Code, each material
advisor, as defined below, (which may include the Managing General Partner and
others, including us, if the Partnerships are reportable transactions), must
file a return with the IRS which identifies the reportable transaction and
describes the potential tax benefits of the reportable transaction. Under
Section 6111(b) of the Code, a "material advisor" for purposes of reporting
reportable transactions to the IRS and for other purposes under the Code is a
person who provides any material aid, assistance, or advice with respect to
organizing, managing, promoting, selling, implementing, insuring, or carrying
out a reportable transaction and who derives gross income for his services of
$50,000 or more with respect to a reportable transaction in which substantially
all of the tax benefits go to natural persons, or $250,000 in any other case. No
filing of a Form 8886 by the Participants in that Partnership would be required
unless, as noted above, a Participant's allocable share of the Partnership's
Section 165 losses separately met the dollar amount thresholds described above
for a Section 165 loss transaction, or if the Partnership is determined to be a
reportable transaction under one of the other types of reportable transactions.
Also, in the first year of filing, a copy must be sent to the IRS's Office of
Tax Shelter Analysis. Again, however, merely disclosing a reportable transaction
to the IRS when required to do so (or as a precautionary measure, in the
Managing General Partner's discretion, if the filing requirement is not clear)
has no effect on the legal determination of whether any claimed tax position by
a Partnership is proper or improper.
Also, under Section 6707A of the Code there is a penalty against any
person who participates in a reportable transaction and fails to properly
disclose the reportable transaction to the IRS as required by Section 6011 of
the Code and Treas. Reg. Section 1.6011-4, which is discussed above. This
penalty potentially could apply to the Participants in a Partnership if their
Partnership was found by the IRS to be a reportable transaction in the future.
The penalty for each failure to properly disclose a reportable transaction is
$10,000 in the case of a natural person, and $50,000 in any other case. However,
if the transaction is a listed transaction, the penalty is $100,000 in the case
of a natural person, and $200,000 in any other case. The penalty is imposed in
addition to any other penalty imposed. If a Partnership were ever to be
determined to be a reportable transaction, the Managing General Partner will
advise its Participants of that determination so that they can begin complying
with their reporting obligations to the IRS.
Material advisors also must maintain a list that identifies each person
with respect to whom the advisor acted as a material advisor for the reportable
transaction (which may include the Participants in a Partnership if the Managing
General Partner determines that either or both of the Partnerships is a
reportable transaction or if the Partnership is ultimately found by the IRS or
the courts to be a reportable transaction) and contains any other information
concerning the transaction as may be required by the IRS.
STATE AND LOCAL TAXES. Each Partnership will operate in states and
localities which impose a tax on it or its Participants based on its assets or
its income. The Partnerships also may be subject to state income tax withholding
requirements on their income or on their Participants' share of their income,
whether their revenues that created the income are distributed to their
Participants or not. Deductions and credits, including the federal marginal well
production credit, which may be available to Participants for federal income tax
purposes, may not be available for state or local income tax purposes. If a
Participant resides in a state which imposes income taxes on its residents, the
Participant will likely 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 a state because of
Partnership operations within that state, he may be entitled to a deduction or
credit against tax owed to his state of residence with respect to the same
income. Also, due to a Partnership's
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operations in a state or other 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.
Prospective Participants are urged to seek advice based on their
particular circumstances from an independent tax advisor to determine the effect
state and local taxes, including gift and death taxes as well as income taxes,
may have on them in connection with an investment in a Partnership.
SEVERANCE AND AD VALOREM (REAL ESTATE) TAXES. Each Partnership may incur
various ad valorem or severance taxes imposed by state or local taxing
authorities on its natural gas and oil wells and/or natural gas and oil
production from the wells. These taxes would reduce the amount of the
Partnership's cash available for distribution to its Participants.
SOCIAL SECURITY BENEFITS AND SELF-EMPLOYMENT TAX. A Limited Partner's
share of income or loss from a Partnership is excluded from the definition of
"net earnings from self-employment." No increased benefits under the Social
Security Act will be earned by Limited Partners and if any Limited Partners are
currently receiving Social Security benefits, their shares of Partnership
taxable income will not be taken into account in determining any reduction in
benefits because of "excess earnings."
An Investor General Partner's share of income or loss from a Partnership
will constitute "net earnings from self-employment" for these purposes. I.R.C.
Section 1402(a). The ceiling for social security tax of 12.4% in 2005 is
$90,000. There is no ceiling for medicare tax of 2.9%. Self-employed individuals
can deduct one-half of their self-employment tax.
FARMOUTS. Under a Farmout by a Partnership, if a property interest,
other than an interest in the drilling unit assigned to the Partnership Well in
question, is earned by the farmee (anyone other than the Partnership) from the
farmor (the Partnership) as a result of the farmee drilling or completing the
well, then the farmee must recognize income equal to the fair market value of
the outside interest earned, and the farmor must recognize gain or loss on a
deemed sale equal to the difference between the fair market value of the outside
interest and the farmor's tax basis in the outside interest. Neither the farmor
nor the farmee would have received any cash to pay the tax. The Managing General
Partner has represented that it will attempt to eliminate or reduce any gain to
a Partnership from a Farmout, if any. However, if the IRS claims that a Farmout
by a Partnership results in taxable income to the Partnership and its position
is ultimately sustained, the Participants in that Partnership would be required
to include their share of the resulting taxable income on their personal income
tax returns, even though the Partnership and its Participants received no cash
from the Farmout.
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. Section 1446. Also, a purchaser of a
foreign Participant's Units may be required to withhold a portion of the
purchase price and the Managing General Partner may be required to withhold with
respect to taxable distributions of real property to a foreign Participant.
These withholding requirements do not obviate United States tax return filing
requirements for foreign Participants. In the event of overwithholding a foreign
Participant must file a United States tax return to obtain a refund. Under
Section 1441 of the Code, for withholding purposes a foreign Participant means a
Participant who is not a United States person and includes a nonresident alien
individual (even if an election has been made to be treated as a U.S. resident
on a joint return), a foreign corporation which is subject to U.S. income tax,
except qualified corporations organized under the laws of Guam, American Samoa,
the Northern Mariana Islands, or the Virgin Islands, a foreign partnership, and
a foreign trust or estate, if the Participant has not certified to his
Partnership the Participant's nonforeign status on IRS Form W-9 or any other
form permitted under the Code. Foreign investors are urged to seek advice based
on their particular circumstances from an independent tax advisor regarding the
applicability of these rules and the other tax consequences of an investment in
a Partnership to them.
ESTATE AND GIFT TAXATION. There is no federal tax on lifetime or
testamentary transfers of property between spouses. The gift tax annual
exclusion in 2005 is $11,000 per donee, which will be adjusted in subsequent
years for
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inflation. Under the Economic Growth and Tax Relief Reconciliation Act of 2001
(the "2001 Tax Act"), the maximum estate and gift tax rate of 47% in 2005 will
be reduced in stages to 46% in 2006 and 45% from 2007 through 2009. Estates of
$1.5 million in 2005, which increases in stages to $2 million in 2006, 2007 and
2008, and $3.5 million in 2009, or less are not subject to federal estate tax to
the extent those exemption amounts were not previously used, in whole or in
part, by the decedent to avoid gift taxes on lifetime gifts in excess of the
annual exclusion amount. Under the 2001 Tax Act, the federal estate tax will be
repealed in 2010, and the maximum gift tax rate in 2010 will be 35%. In 2011 the
federal estate and gift taxes are scheduled to be reinstated under the rules in
effect before the 2001 Tax Act was enacted.
CHANGES IN THE LAW. A Participant's investment in a Partnership may be
affected by changes in the tax laws. For example, in 2003 the top four federal
income tax brackets for individuals were reduced through December 31, 2010,
including reducing the top bracket to 35% from 38.6%. The lower federal income
tax rates will reduce to some degree the amount of taxes a Participant can save
by virtue of his share of his Partnership's deductions for Intangible Drilling
Costs, depletion and depreciation, and marginal well production credits, if any.
On the other hand, the lower federal income tax rates also will reduce the
amount of federal income tax liability incurred by a Participant on his share of
the net income of his Partnership. There is no assurance that the federal income
tax brackets discussed above will not be changed again before 2011. Prospective
Participants are urged to seek advice based on their particular circumstances
from an independent tax advisor with respect to the impact of recent legislation
on an investment in a Partnership and the status of legislative, regulatory or
administrative developments and proposals and their potential effect on them if
they invest in a Partnership.
We consent to the use of this tax opinion letter as an exhibit to the
Registration Statement, and all amendments to the Registration Statement,
including post-effective amendments, and to all references to this firm in the
Prospectus.
Very truly yours,
/s/ Kunzman & Bollinger, Inc.
KUNZMAN & BOLLINGER, INC.