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