PROSPECTUS
PDC 1996-1997 DRILLING PROGRAM
$1,000,000 Minimum Subscriptions
PDC 1996-1997 Drilling Program (the "Program") is a series of up to
eight limited partnerships which will be formed to drill, own, and operate
natural gas wells in West Virginia, Ohio, Pennsylvania, New York, Kentucky,
Michigan and/or Illinois. Interests in the Program will be offered over a
two-year period with interests in the partnerships designated "PDC
1996-_ Limited Partnership" being offered only during 1996 and interests
in the partnerships designated "PDC 1997-_ Limited Partnership" being
offered only during 1997. The primary purpose of the partnerships will
be to generate revenue from gas sales and distribute the proceeds to the
partners. The economic benefits of the investment are expected to include
deductions in 1996 (with respect to the partnerships designated "PDC 1996-
_ Limited Partnership") and in 1997 (with respect to partnerships
designated "PDC 1997-_ Limited Partnership") for intangible drilling costs
and subsequently when wells are in production for depletion. See "Summary
- -- Terms of the Offering."
- Units of preformation general partnership interest and limited
partnership interest (hereinafter, "Units") in gas development
limited partnerships are offered.
- The managing general partner anticipates that, if the minimum
offering of $1 million is achieved, approximately 89.3% of the total
capital contributions will be utilized for gas well drilling and
completion activities. See "Source of Funds and Use of Proceeds."
THESE SECURITIES ARE SPECULATIVE AND INVOLVE A HIGH DEGREE OF RISK.
SEE "RISK FACTORS." Significant risks include, but are not limited to:
- The drilling of gas wells is highly risky and includes the
possibility of a total loss of one's investment.
- Total reliance is on the managing general partner for management and
control of each partnership.
- No prospects for gas drilling have yet been selected and therefore
no investor will have an opportunity to evaluate any of the
prospects before investing in the partnership.
- Investors who purchase general partnership interests may be subject
to unlimited liability. All general partnership interests will be
converted into limited partnership interests upon completion of
drilling.
- Revenues of each partnership are directly related to natural gas
prices which cannot be predicted.
- An investment in the Program is illiquid -- investors may not be
able to sell their partnership interests.
- Investment is suitable only for investors having substantial
financial resources and who desire a long-term investment.
- Significant tax considerations are involved in an investment,
including
-- possible modification or elimination of tax benefits
-- possible loss of partnership classification
-- limited partners must have substantial current taxable income
from passive trade or business activities to benefit from tax
losses arising from the particular partnership
-- possible recognition of taxable income by an Investor Partner
with no corresponding cash distribution by the partnership
- The partnerships are subject to various conflicts of interest
arising out of their relationship with the managing general partner,
including the fact that the dealer manager is an affiliate of the
managing general partner and its due diligence examination
concerning this offering cannot be considered to be independent.
- Substantial compensation and fees are payable by the partnership to
the managing general partner and affiliates upon formation and
throughout the life of the partnership.
The minimum capital for each partnership to be raised from investors is
$1 million, while the maximum capital is $10 million. The managing
general partner has complete discretion as to when the offering of a
particular partnership terminates at any point after the minimum
subscription is reached. Nevertheless, it is the intention of the
managing general partner to terminate the offering of each partnership
(assuming the minimum subscription has been reached) at or near the time
of the respective targeted closing dates for each partnership. No
offering of a partnership designated "PDC 1996-_ Limited Partnership" is
permitted to extend beyond December 31, 1996 and no offering of a
partnership designated "PDC 1997-_ Limited Partnership" is permitted to
extend beyond December 31, 1997. See "Terms of the Offering -- General."
No particular partnership will be funded if the minimum subscription is
not attained. Moreover, no Units in a Partnership will be offered or sold
after the closing of the offering of that Partnership.
Subscription proceeds of each Partnership will be held in a separate
interest-bearing escrow account at PNC Bank, N.A., Pittsburgh,
Pennsylvania (the "Escrow Agent"). In the event that the minimum required
subscription is not realized with respect to a Partnership, that
Partnership will not be funded, and the Escrow Agent will promptly return
all subscription proceeds to the respective subscribers in full with any
interest earned thereon and without any deduction therefrom. See "Terms
of the Offering -- General."
Units are being offered at a price of $20,000 per Unit. The minimum
subscription is one-quarter Unit ($5,000). The managing general partner
in its discretion must consent before subscriptions for less than full
Units will be accepted, after reviewing state law suitability requirements
and the financial capability of the prospective investor. Units will not
be sold to tax-exempt investors or to foreign investors.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE GOVERNMENTAL AGENCY, NOR HAS THE
COMMISSION OR ANY STATE GOVERNMENTAL AGENCY PASSED UPON THE ACCURACY OR
ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
NEITHER THE ATTORNEY GENERAL OF THE STATE OF NEW YORK NOR THE ATTORNEY
GENERAL OF THE STATE OF NEW JERSEY NOR THE BUREAU OF SECURITIES OF THE
STATE OF NEW JERSEY HAS PASSED ON OR ENDORSED THE MERITS OF THIS OFFERING.
ANY REPRESENTATION TO THE CONTRARY IS UNLAWFUL.
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Underwriting
Price to Discounts and
Proceeds to the
Public Commissions
Partnerships(1)
Per Unit . . . . . . . . . . . . $ 20,000 $ 2,100 (10.5%)
$ 17,900 (89.5%)
Total Minimum. . . . . . . . . . $ 1,000,000 $ 105,000 (10.5%)
$ 895,000 (89.5%)
Total Maximum. . . . . . . . . . $50,000,000 $5,250,000 (10.5%)
$44,750,000 (89.5%)
(1) Before deducting expenses payable by the Partnership estimated at
$100,000 if the minimum number of Units is sold ranging to $300,000
if the maximum number of Units is sold, including legal, accounting,
printing, and filing and registration fees. The Managing General
Partner will pay Organization and Offering Costs in excess of 10
1/2% of Subscriptions.
PDC Securities Incorporated, Dealer Manager
and an Affiliate of the Managing General Partner
103 East Main Street
Bridgeport, West Virginia 26330
(800) 624-3821
A Member of the National Association of Securities Dealers, Inc. and
Securities Investor Protection Corporation
The date of this Prospectus is December 19, 1995.
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Each partnership intends to furnish to investors annual reports
containing audited financial statements, a report thereon by its
independent certified public accountants, and a semiannual report
containing unaudited financial information for the first six months of
each year.
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<PAGE>
SUMMARY
This summary is qualified in its entirety by the more detailed
information appearing elsewhere in this Prospectus. Prospective investors
are directed to the "Glossary of Terms" at the end of this Prospectus,
which defines the capitalized terms appearing throughout the Prospectus.
Terms of the Offering
The Program. PDC 1996-1997 Drilling Program (the "Program") is a series
of up to eight limited partnerships (each hereinafter referred to as a
"Partnership" or where the context so provides as the "Partnerships") to
be formed under and governed by the West Virginia Uniform Limited
Partnership Act. Units will be offered over a two-year period with Units
in the Partnerships designated "PDC 1996-_ Limited Partnership" being
offered only during 1996 and Units in the Partnerships designated "PDC
1997-_ Limited Partnership" being offered only during 1997. The rights
and obligations of the Partners of each Partnership will be governed by a
Limited Partnership Agreement (the "Partnership Agreement"), the form of
which is attached to the Prospectus as Appendix A. For a description of
the principal terms of the Partnership Agreement, see "Summary of
Partnership Agreement." The managing general partner of each Partnership
will be Petroleum Development Corporation (hereinafter referred to as the
"Managing General Partner"). The subscription periods for all
Partnerships designated "PDC 1996-_ Limited Partnership" and those
designated "PDC 1997-_ Limited Partnership" will terminate on December 31,
1996 and December 31, 1997, respectively, unless earlier terminated or
withdrawn by the Managing General Partner.
A total of 2,500 Units at $20,000 per Unit, aggregating $50,000,000, is
being offered. "Unit" means a Partnership interest of a Limited Partner
or of an Additional General Partner purchased by an Investor Partner by an
investment of $20,000. This interest is the right and obligation to share
a proportional part of the Investor Partners' share of Partnership income,
expense, assets and liabilities. The fractional interest purchased by a
one unit investment in the Investor Partners' interest in the Partnership
income, expense, assets, or liabilities (see the table under "Summary --
Participation in Costs and Revenues") is the ratio of one unit to the
total number of units sold. Investors may choose to purchase units of
general partnership interest or units of limited partnership interest.
The Managing General Partner will convert all units of general partnership
interest into units of limited partnership interest upon completion of
drilling. Units will not be sold to tax-exempt investors or to foreign
investors. The minimum investment by an investor is $5,000.
The minimum number of Units which must be sold to allow a Partnership
to be funded is 50 Units, or $1,000,000. The maximum subscription for any
Partnership is $10,000,000 (500 Units). The Managing General Partner has
complete discretion as to when the offering of a particular Partnership
terminates at any point after the minimum subscription is reached. It is
the intention of the Managing General Partner to terminate the offering of
each Partnership (assuming the minimum subscription has been reached) at
or near the time of the respective targeted closing dates for each
Partnership, which are set forth in "Terms of the Offering -- General."
No offering of any Partnership designated "PDC 1996-_ Limited Partnership"
or "PDC 1997-_ Limited Partnership" is permitted to extend beyond December
31, 1996 or December 31, 1997, respectively.
All subscriptions are payable in cash upon subscription. The execution
of the Subscription Agreement by a subscriber constitutes a binding offer
to buy Units in a Partnership. Once an investor subscribes for Units,
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that investor will not be able to revoke his Subscription. Escrowed
Subscriptions will be promptly returned to the respective subscribers of
the particular Partnership if the Partnership is not closed by the
sixtieth day following the anticipated offering termination date with
respect to each respective Partnership, or if PDC 1996-D Limited
Partnership or PDC 1997-D Limited Partnership has not closed on or before
December 31, 1996 or December 31, 1997, respectively. Subscription
proceeds of each Partnership will be held in a separate interest-bearing
escrow account at PNC Bank, N.A., Pittsburgh, Pennsylvania (the "Escrow
Agent"). In the event that the minimum required subscription of
$1,000,000 is not realized in the offering of Units of any particular
Partnership, that Partnership will not be funded, and the Escrow Agent
will promptly return all subscription proceeds with respect to the
particular Partnership to the respective subscribers in full with any
interest earned thereon and without any deduction therefrom. For a full
discussion of the various terms of the offering, see "Terms of the
Offering" below.
The Partnerships are being formed to drill, own, and operate natural gas
wells in West Virginia, Ohio, and/or Pennsylvania and to produce and sell
gas from these wells. The Managing General Partner may determine to drill
wells in New York and Virginia. Of the offering proceeds available for
drilling operations, the Managing General Partner plans to utilize all
such proceeds in the drilling of development wells but may utilize up to
10% on one or more exploratory wells. See "Proposed Activities" and
"Glossary of Terms" for the definitions of "Development Well,"
"Exploratory Well," and other terms which are used in this Prospectus.
The address and telephone number of the Partnerships and Petroleum
Development Corporation, the Managing General Partner, are 103 East Main
Street, P.O. Box 26, Bridgeport, West Virginia 26330 and (800) 624-3821.
Conversion of Units by Additional General Partners. Additional General
Partners (those investors who purchase Units of general partnership
interest) of a particular Partnership will have the right to convert their
Units into Units of limited partnership interest and thereafter become
limited partners of that Partnership. Moreover, the Managing General
Partner will convert all Units of general partnership interest of a
particular Partnership into Units of limited partnership interest upon
completion of drilling of that Partnership. See "Tax Considerations --
Conversion of Interests," "Terms of the Offering -- Conversion of Units by
Additional General Partners," and "Proposed Activities -- Insurance."
Unit Repurchase Program. Beginning with the third anniversary of the
date of the first cash distribution of the particular Partnership,
Investor Partners (those persons who invest in a Partnership, either as
Additional General Partners or as Limited Partners) of that Partnership
may offer their Units to the Managing General Partner for repurchase.
Repurchase of Units is subject to certain conditions, including the
financial ability of the Managing General Partner to purchase the Units
and certain opinions of counsel. Subject to such financial condition and
opinions of counsel, the Managing General Partner will offer annually to
repurchase for cash a minimum of 10% of the Units originally subscribed to
in the Partnership. Subject to such conditions, the Managing General
Partner is obligated to purchase all Units presented to it by investors,
up to the 10% ceiling as stated above. The repurchase price will be based
upon a minimum of three times cash distributions during the 12 months
preceding receipt of the request for repurchase or some greater amount
which is solely in the discretion of the Managing General Partner. Such
repurchase price will not necessarily represent the fair market value of
the Units. See "Terms of the Offering -- Unit Repurchase Program" and
"Tax Considerations -- Conversion of Interests."
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<PAGE>
Suitability Standards -- Long-Term Investment. The Managing General
Partner has instituted strict suitability standards for investment in the
Partnerships. The high degree of investment risk together with the
restrictions on the sale of Units, lack of a market for the Units, and the
tax consequences of the sale of Units makes investment in the Partnerships
suitable only for persons who are able to hold their Units on a long-term
investment basis. See "Terms of the Offering -- Investor Suitability."
Risk Factors. This offering involves numerous risks, including the
risks of oil and gas drilling, the risks associated with investments in
oil and gas drilling programs, and significant tax considerations. See
"Risk Factors" and "Tax Considerations." Each prospective investor should
carefully consider a number of significant risk factors inherent in and
affecting the business of the Partnerships and this offering, including
the following:
Special Risks of the Partnerships:
- The drilling and completion operations to be undertaken by each
Partnership for the development of natural gas reserves involve the
possibility of a total loss of an investment in a Partnership.
- The Managing General Partner will have the exclusive management and
control of all aspects of the business of each Partnership. No
investor will be permitted to take part in the management or in the
decision-making of the Partnership.
- No Prospects have been or will be selected for acquisition by a
particular Partnership until after activation of that Partnership.
Therefore, no investor will have an opportunity to evaluate any of
the Prospects before investing in a Partnership. Because all
subscriptions are irrevocable, because the offering period for a
particular Partnership can extend over a number of months, and
because no Prospect will be acquired until activation of a
Partnership, delays in the investment of proceeds from the initial
subscription date are likely.
- Investors who invest as Additional General Partners will have
unlimited liability for all obligations and liabilities of creditors
and claimants arising during such time they were Additional General
Partners from the conduct of Partnership operations and if such
liabilities exceed the Partnership's assets and insurance and the
assets of the Managing General Partner (which has agreed to indemnify
the Additional General Partners).
- Investors in a Partnership must assume the risks of an illiquid
investment. Investors may be unable to sell their Partnership
interests. There will be no market for the Units.
- The Partnerships are subject to various conflicts of interest arising
out of their relationship with the Managing General Partner,
including: the Managing General Partner currently manages oil and
gas drilling programs similar to the Partnerships; the Managing
General Partner decides which Prospects each Partnership will
acquire; the Managing General Partner will act as operator and will
furnish drilling and completion services to the Partnerships; the
Managing General Partner is general partner of numerous other
partnerships and owes duties of good-faith dealing to such other
partnerships; and the dealer manager, an Affiliate of the Managing
General Partner, will receive sales commissions as a result of sales
of Units.
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<PAGE>
- The Managing General Partner and Affiliates will receive fees and
compensation throughout the life of each Partnership. If and to the
extent these fees and compensation create conflicts between the best
interests of the investors and the best interests of the Managing
General Partner, the Managing General Partner may have incentives to
act in a manner not in the best interest of the Partners.
- It is possible that some or all of the insurance coverage which the
Partnership has available may become unavailable or prohibitively
expensive. In such event, the investors could be subject to greater
risk of loss of their investment since less insurance would be
available to protect against casualty losses.
- To the extent that less subscription proceeds are raised, the
Partnership will be able to drill fewer wells, the result of which
there will be less diversification of the investors' investment and
less ability of the Partnership to spread the risk of loss.
- The Managing General Partner and Affiliates may also purchase Units,
the effect of which may be to assure that the minimum aggregate
subscription amount is reached.
- The Partnership is permitted to drill one or more Exploratory Wells.
Drilling Exploratory Wells involves greater risks of Dry Holes and
loss of the Partnership's investment.
Risks Pertaining to Natural Gas Investments:
- Natural gas drilling is a highly speculative activity. There is a
possibility that wells drilled may not produce natural gas. Even
wells which are productive may not produce gas in sufficient
quantities to return all or a significant portion of the investment.
- Future gas prices are unpredictable. If gas prices go down, investor
returns will go down.
- Access to markets for gas produced by wells may be restricted as a
result of many factors, including distances to existing pipelines, an
oversupply of crude oil and natural gas, changing demand from weather
conditions, and regulations set by Federal and state governmental
authorities, thus impeding or delaying revenues to the Partnerships.
Tax Risks:
- No ruling has been obtained from the Internal Revenue Service (the
"Service") as to partnership status of the Partnerships.
- Investment as an Additional General Partner may not be advisable for
a person whose taxable income from all sources is not recurring or is
not subject to high marginal federal income tax rates.
- Investment as a Limited Partner may be less advisable for a person
who does not have substantial current taxable income from passive
trade or business activities.
- Federal income tax payable by an Investor Partner by reason of his
distributive share of Partnership income for any year may
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exceed the cash distributed to such Partner by the Partnership.
- Even though the Partnerships will not register with the Service as
"tax shelters," there still remains a likelihood of an audit of the
Partnerships' returns by the Service.
- Of the total program proceeds, the 10 1/2% utilized for syndication
costs, offering costs, and commissions, is nondeductible for the life
of the Partnership, and 2-1/2% is utilized for the management fee,
some or all of which may not be deductible and some of which may be
deductible only over a 60 month period.
Compensation of the Managing General Partner
The following is a tabular presentation of the items of compensation
respecting the Managing General Partner:
<TABLE>
<S> <S> <S>
Recipient Form of Compensation Amount
Managing General Partnership interest 20% interest(1)
Partner
Managing General Management Fee 2.5% of Subscriptions
Partner (non-recurring fee)(2)
Managing General Sale of Leases to Cost, or fair market
Partner Partnerships value if materially less
than Cost(3)
Managing General Contract drilling rates Competitive industry
Partner rates(3)
Managing General Operator's Per-Well Charges $300 per well per
Partner month(3)
Managing General Direct Costs Cost(3)
Partner
Managing General Payment for equipment, Competitive prices(3)
Partner and supplies and other services
Affiliates
Affiliate Brokerage sales commissions; 10.5% of Subscriptions
reimbursement of due $105,000 ranging to
diligence and marketing $5.25 million(4)
support expenses; wholesaling
fees
</TABLE>
_____________________
(1) The Managing General Partner will contribute to the Partnerships an
amount equal to at least 21-7/8% of the aggregate contributions of
the Investor Partners. The Managing General Partner will subordinate
its share of Partnership distributions. See "Participation in Costs
and Revenues," below.
(2) The one-time fee will range from $25,000 if the minimum number of
Units is sold to $1,250,000 if the maximum number of Units is sold.
(3) Cannot be quantified until Partnership is conducting business.
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(4) PDC Securities Incorporated, an Affiliate of the Managing General
Partner, will receive as Dealer Manager of the offering sales
commissions, reimbursement of due diligence and marketing support
expenses, and wholesaling fees payable from the Subscriptions of the
Investor Partners of $5,250,000 if the maximum number of Units is
sold ranging to $105,000 if the minimum number of Units is sold. PDC
Securities Incorporated may, as Dealer Manager, reallow such
commissions and due diligence and marketing support expenses in whole
or in part to NASD licensed broker-dealers for sale of the Units,
reimbursement of due diligence and marketing support expenses, and
other compensation, but will retain the wholesaling fees, which will
equal 0.5% of Subscriptions and will range from $5,000 if the minimum
number of Units is sold to $250,000 if the maximum number of Units is
sold.
Participation in Costs and Revenues
Partnership profits and losses will be allocated 80% to the Investor
Partners and 20% to the Managing General Partner throughout the term of
each Partnership. The Partnership is structured to provide preferred cash
distributions to Investor Partners so that they might receive cash
distributions equal to a minimum of 10% of their Subscriptions per year on
a cumulative basis for the first five years of partnership well
operations. To help investors achieve this level of cash distributions,
the Managing General Partner will subordinate up to 50% of its share of
Partnership distributions for the five year period commencing upon the
first distribution of revenues after all Partnership wells have been
placed in production. Thus Investor Partners could receive up to 90% of
Partnership distributions during the subordination period. See
"Participation in Costs and Revenues -- Revenues -- Preferred Cash
Distributions," below.
The table below summarizes the participation in the costs and revenues
of the Partnerships by the Managing General Partner and the Investor
Partners, taking account of the Managing General Partner's contribution to
the capital of the Partnerships. The table is reproduced in full, with
footnotes, under "Participation in Costs and Revenues."
<TABLE>
<S> <S> <S>
Managing
Investor General
Partners Partner
Partnership Costs
Broker-dealer Commissions and Expenses(1). . . 100% 0%
Management Fee . . . . . . . . . . . . . . . . 100% 0%
Lease Costs. . . . . . . . . . . . . . . . . . 0% 100%
Tangible Equipment . . . . . . . . . . . . . . 0% 100%
Drilling and Completion Costs. . . . . . . . . 80% 20%
Intangible Drilling and Development Costs. . . 100% 0%
Operating Costs. . . . . . . . . . . . . . . . 80% 20%
Direct Costs . . . . . . . . . . . . . . . . . 80% 20%
Administrative Costs . . . . . . . . . . . . . 0% 100%
Partnership Revenues
Sale of Oil and Gas Production(2). . . . . . . 80% 20%
Sale of Productive Properties. . . . . . . . . 80% 20%
Sale of Equipment. . . . . . . . . . . . . . . 0% 100%
Sale of Undeveloped Leases . . . . . . . . . . 80% 20%
Interest Income. . . . . . . . . . . . . . . . 80% 20%
</TABLE>
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____________________
(1) Organization and Offering Costs, net of the Dealer Manager
commissions, discounts, due diligence expenses, and wholesaling
fees, of the Partnerships will be paid by the Managing General
Partner and not from Partnership funds. In addition, Organization
and Offering Costs, including commissions, in excess of 10 1/2% of
Subscriptions will be paid by the Managing General Partner, without
recourse to the Partnerships.
(2) To the extent that Investor Partners receive preferred cash
distributions (see "Participation in Costs and Revenues -- Revenues -
Preferred Cash Distributions"), the allocations for Investor Partners
will be increased accordingly and the allocation for the Managing
General Partner will likewise be decreased.
The Managing General Partner will pay for all Leases and tangible
well equipment. The entire Capital Contribution of the Investor Partners,
after payment of brokerage commissions, due diligence reimbursement, and
the Management Fee, will be utilized to pay for intangible drilling costs.
In the event that the Intangible Drilling Costs exceed the funds of the
Investor Partners available for payment of Intangible Drilling Costs
(herein "excess IDC"), a portion of the Capital Contribution of the
Managing General Partner may be used to pay such excess IDC. If the cost
of Leases, tangible well equipment, and excess IDC were to exceed the
Managing General Partner's Capital Contribution of 21-7/8% of the
aggregate Capital Contribution of the Investor Partners, then the Managing
General Partner will increase its Capital Contribution to fund such
additional capital requirements.
Application of Proceeds
The Managing General Partner estimates that the proceeds from the
aggregate contributions to the capital of a Partnership by the Investor
Partners and the Managing General Partner will be applied as follows,
assuming the minimum number of Units is sold. For a more extensive
presentation of the use of proceeds, see "Source of Funds and Use of
Proceeds" later in the Prospectus.
<TABLE>
<S> <S>
Activity Percentage of Total
Capital Contributions
Drilling and Completion Costs. . . . . . . . . . . . . . 89.3%
Organization and Offering Costs. . . . . . . . . . . . . 8.6%
Management Fee . . . . . . . . . . . . . . . . . . . . . 2.1%
Total. . . . . . . . . . . . . . . . . . . . . . . . . . 100.0%
</TABLE>
Tax Considerations; Opinion of Counsel
The Managing General Partner has received an opinion from its counsel,
Metzger, Hollis, Gordon & Mortimer, Washington, D.C., concerning all
material federal income tax issues applicable to an investment in the
Partnerships. To be fully understood, the complete discussion of these
matters set forth in the full tax opinion in Appendix D should be read by
each prospective investor partner. Based upon current laws, regulations,
interpretations, and court decisions, Metzger, Hollis, Gordon & Mortimer
has rendered its opinion that (i) the material federal income tax benefits
in the aggregate from an investment in the Partnership will be realized;
(ii) each Partnership will be treated as a partnership for federal income
tax purposes and not as a corporation and not as an association taxable as
a corporation; (iii) to the extent the Partnership's wells are timely
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drilled and amounts are timely paid, the Partners will be entitled to
their pro rata share of the Partnership's IDC paid in 1996 with respect to
Partnerships designated as "PDC 1996-_ Limited Partnership" and in 1997
with respect to Partnerships designated as "PDC 1997-_ Limited
Partnership"; (iv) neither the at risk nor the adjusted basis rules will
limit the deductibility of losses generated from the Partnership; (v) the
interests of persons who purchase Units of general partnership interest
will not be considered a passive activity within the meaning of Code
Section 469 and losses generated while such general partnership interest
is so held will not be limited by the passive activity provisions; (vi)
Limited Partners' interests (other than those held by investors of general
partnership interest who convert their interests into Limited Partners'
interests) will be considered a passive activity within the meaning of
Code Section 469 and losses generated therefrom will be limited by the
passive activity provisions; (vii) the Partnership will not be terminated
solely as the result of the conversion of Partnership interests; (viii) to
the extent provided herein, the Partners' distributive shares of
Partnership tax items will be determined and allocated substantially in
accordance with the terms of the Partnership Agreement; (ix) the
Partnership will not be required to register with the Service as a tax
shelter; and (x) each Partner will be entitled to his distributive share
of the Partnership's cost recovery deduction.
Due to the lack of authority, or the essentially factual nature of the
question, counsel expresses no opinion on the following: (i) the impact
of an investment in the Partnership on an Investor's alternative minimum
tax, due to the factual nature of the issue; (ii) whether, under Code
Section 183, the losses of the Partnership will be treated as derived from
"activities not engaged in for profit," and therefore nondeductible from
other gross income, due to the inherently factual nature of a Partner's
interest and motive in engaging in the transaction; (iii) whether any of
the Partnership's properties will be considered "proven" for purposes of
depletion deductions, due to the factual nature of the issue; (iv) whether
any interest incurred by a Partner with respect to any borrowings will be
deductible or subject to limitations on deductibility, due to the factual
nature of the issue; and (v) whether the fees to be paid to the Managing
General Partner and to third parties will be deductible, due to the
factual nature of the issue.
Rights of the Investor Partners
The rights of the Investor Partners will be governed by the Partnership
Agreement, which is attached to this Prospectus as Appendix A. The
following is a summary of the more significant of their rights.
- The Managing General Partner will have the exclusive right to manage
and control all aspects of the business of the Partnership. No
investor will have any voice in the day-to-day business operations of
the Partnership.
- Profits and losses are to be allocated and cash is to be distributed
in the manner discussed in the section entitled "Participation in
Costs and Revenues."
- Investors owning 10% or more of the then outstanding Units have the
right to ask the Managing General Partner to call a meeting of the
Investor Partners. Each Unit is entitled to one vote on all matters.
A vote of a majority of the then outstanding Units is required to
approve any sale of all or substantially all of the Partnership's
assets; the removal of the Managing General Partner and the election
of a new managing general partner; the dissolution of the
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Partnership; any non-ministerial amendment to the Partnership
Agreement; and the cancellation of contracts for services with the
Managing General Partner.
- The Managing General Partner has agreed to indemnify each investor
who owns Units of general partnership interest for obligations,
losses, or judgments of the Partnership or the
Managing General Partner which exceed the amount of applicable
insurance coverage and amounts which would become available from the
sale of all Partnership assets.
- The Managing General Partner is obligated to furnish investors semi-
annual and annual reports. The reports will contain financial
statements (audited in the annual reports), information regarding
transactions between the Managing General Partner and the
Partnership, reserve information prepared by an independent petroleum
engineer, and information regarding the Partnership's activities.
- Investors may sell, transfer, or assign their Units, subject to the
consent of the Managing General Partner and provided that the
transferee satisfies all applicable suitability requirements.
- Investors have the right to inspect the Partnership's books and
records at any reasonable time.
RISK FACTORS
Investment in the Partnerships involves a high degree of risk and is
suitable only for investors of substantial financial means who have no
need of liquidity in their investments. In analyzing this offering,
investors should carefully consider the following risk factors.
Special Risks of the Partnerships
Speculative Nature of Investment; Investment Suitable Only for
Financially Able. The drilling and completion operations to be undertaken
by each of the Partnerships for the development of natural gas reserves
involve the possibility of a total loss of an investment in a Partnership.
Drilling activities may be unprofitable, not only from non-productive
wells, but from wells which do not produce natural gas in sufficient
quantities or quality to return a profit on the amounts expended.
Investment is suitable only for individuals who are financially able to
withstand a total loss of their investment. See "Terms of the Offering --
Investor Suitability."
Exclusive Reliance Upon Managing General Partner for Management of
Partnerships; Investor Partners May Not Manage. The Managing General
Partner will exclusively manage and control all aspects of the business of
each Partnership and will make all decisions respecting the business of
each Partnership. The Investor Partners will not take part in the
management of any Partnership. See Article VI and Section 7.01 of the
Partnership Agreement.
Prospects Not Yet Identified or Selected; No Opportunity for Investors
to Evaluate Prospects. The Managing General Partner has not selected any
Prospect for acquisition by any Partnership and will not select Prospects
for a particular Partnership until after the activation of that
Partnership. Investor Partners will not have an opportunity before
purchasing Units to evaluate for themselves the relevant geophysical,
geological, economic or other information regarding the Prospects to be
selected. Because all Subscriptions are irrevocable, because the offering
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period for a particular Partnership can extend over a number of months,
and because no Prospect will be acquired until after activation of that
Partnership, delays in the investment of proceeds from the initial
subscription date are likely.
Unlimited Liability of Additional General Partners. Under West Virginia
law, the state in which each Partnership is to be formed, general partners
of a partnership have unlimited liability with respect to that
partnership; therefore, the Additional General Partners will be liable
individually and as a group for all obligations and liabilities of
creditors and claimants, whether arising out of contract or tort, in the
conduct of Partnership operations. Additional General Partners may be
subjected to liability for amounts in excess of their Subscriptions, the
assets of the Partnership, including insurance coverage, and the assets of
the Managing General Partner, which has agreed to indemnify the Additional
General Partners.
Compensation Payable to the Managing General Partner and Affiliates;
Possible Conflicts of Interest. The Managing General Partner and
Affiliates will receive compensation throughout the life of the
Partnership. The Managing General Partner will contribute to the
Partnerships an amount equal to not less than 21-7/8% of the Capital
Contributions of the Investor Partners; the Managing General Partner is
moreover obligated to pay for all Lease and tangible drilling Costs with
respect to each Partnership organized. The Managing General Partner's
share of operating profits in each Partnership will be 20% (subject to the
preferred cash distribution policy). The Partnership at closing of the
Partnership will pay to the Managing General Partner a one-time Management
Fee equal to 2.5% of total Subscriptions. The Partnership will pay the
Managing General Partner as operator for drilling and completing the
Partnership's wells an amount equal to $60 per foot for the first 2,200
feet of well depth plus $16 per foot for each additional foot below 2,200
feet to the deepest penetration with respect to each well completed and
placed into production, plus actual intangible costs of extra zone
completions, and an amount equal to $33 per foot for the first 2,200 feet
of well depth plus $9 per foot for each additional foot below 2,200 feet
to the deepest penetration of each well which the Managing General Partner
determines not to complete. During the production phase of operations,
the Managing General Partner as operator will receive a monthly fee of
$225 per well for operations and field supervision and $75 per well for
accounting, engineering, management, and general and administrative
expenses for producing wells. The Partnership will reimburse the Managing
General Partner for all documented out-of-pocket expenses incurred on
behalf of the Partnership.
The Managing General Partner and its Affiliates may enter into the
transactions with the Partnership for services, supplies, and equipment
and will be entitled to compensation at competitive prices and terms as
determined by reference to charges of unaffiliated companies providing
similar services, supplies, and equipment. PDC Securities Incorporated,
an Affiliate of the Managing General Partner, will receive a fee as Dealer
Manager equal to 10 1/2% of the subscription proceeds (ranging from
$105,000 if the minimum number of Units is sold to $5,250,000 if the
maximum number of Units is sold) for sales commissions, reimbursement of
bona fide due diligence expenses, and wholesaling fees. PDC Securities
Incorporated, as Dealer Manager, may reallow such sales commissions and
expenses in whole or in part to NASD-licensed broker-dealers for sale of
the Units but will retain the wholesaling fees. See "Compensation to the
Managing General Partner and Affiliates."
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If and to the extent these fees and compensation create conflicts
between the best interests of the Investor Partners and the best interests
of the Managing General Partner, the Managing General Partner may have
incentives to act in a manner not in the best interest of the Investor
Partners. For example, the Managing General Partner could have an
incentive to continue to operate wells which were no longer economic to
the Partnership, in order to continue to receive the operating fees. In
view of the fact that the Managing General Partner has a fiduciary duty to
act in furtherance of the best interests of the Investor Partners (see
"Fiduciary Responsibility of the Managing General Partner"), the Managing
General Partner will resolve such conflicts in favor of the interests of
the Investor Partners.
Irrevocable Subscriptions; Escrow of Subscription Funds. The execution
of the Subscription Agreement by a subscriber constitutes a binding offer
to buy Units in a Partnership. Once an investor subscribes for Units,
that investor will not be able to revoke his Subscription. Subscription
proceeds of each Partnership will be held in a separate interest-bearing
escrow account with PNC Bank, N.A. In the event that the offering of
Units in a particular Partnership has not closed by the sixtieth day
following the anticipated offering termination date, the Managing General
Partner will cause all escrowed funds to be promptly returned to the
respective investors of the particular Partnership which has not closed
with any interest earned thereon and without any deduction therefrom. If
the respective offerings of Units in PDC 1996-C Limited Partnership or PDC
1996-D Limited Partnership have not closed on or before December 31, 1996
or the respective offerings of PDC 1997-C Limited Partnership or PDC 1997-
D Limited Partnership have not closed on or before December 31, 1997, the
escrowed funds with respect to that particular offering which has not
closed will be promptly returned to those respective investors with any
interest earned thereon and without any deduction therefrom.
Speculative Nature of Prospect Acquisitions -- No Assurance of Gas
Production. The selection of Prospects for natural gas drilling is
inherently speculative. The Managing General Partner cannot predict
whether any Prospect will produce natural gas or commercial quantities of
natural gas. See "Proposed Activities -- Acquisition of Undeveloped
Prospects."
Illiquid Investment; Restrictions on Transferability of Units.
Investors in any Partnership must assume the risks of an illiquid
investment. Investors may not be able to sell their Partnership
interests. There will be no market for the Units. See "Transferability
of Units."
Possibility of Reduction or Unavailability of Insurance; Possible
Greater Risk of Loss to Investors. It is possible that some or all of the
insurance coverage which the Partnership has available may become
unavailable or prohibitively expensive. In such case, the Managing
General Partner may elect to change the insurance coverage. Upon such
change, Additional General Partners could become Limited Partners. See
"Proposed Activities -- Insurance." Additional General Partners who
elected to remain Additional General Partners could be exposed to
additional financial risk due to the reduced insurance coverage and due to
the fact that Additional General Partners would continue to be
individually liable for all obligations and liabilities of the
Partnership. On the other hand, Additional General Partners who elected
to become Limited Partners could lose or suffer deferral of some or all of
the available tax deductions and credits and thereby be subject to passive
activity treatment for Partnership deductions and credits. See "Tax
Considerations -- Passive Loss and Credit Limitations." All Investor
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Partners could be subject to greater risk of loss of their investment
since less insurance would be available to protect from casualty losses.
Less Diversification of Risks If Less Subscription Proceeds; Greater
Risk of Loss to Investors. The Managing General Partner intends to spread
the risk of natural gas drilling by participating in the drilling of wells
on a number of different Prospects; however, the Managing General Partner
will be able to drill approximately five wells if only the minimum amount
of Subscriptions is obtained in a Partnership. A Partnership subscribed
at the minimum level would be able to participate in fewer Prospects,
thereby increasing the risk to the Investor Partners. As the Partnership
size increases, the number of wells will increase, thereby increasing the
diversification of the Partnership. However, if the Managing General
Partner is unable to secure sufficient attractive Prospects for a larger
partnership, it is possible that the average quality of the wells drilled
could decline. In addition, greater demands will be placed on the
management capabilities of the Managing General Partner in larger
partnerships.
Conflicts of Interest Between Managing General Partner and Partnerships.
The continued active participation by the Managing General Partner and its
Affiliates in oil and gas activities for their own accounts and on behalf
of other partnerships organized or to be organized by them, their sale of
Leases to and other transactions with the Partnerships, and the manner in
which Partnership revenues are allocated create conflicts of interest with
the Partnerships. In this regard, specific conflicts include the
following: the Managing General Partner manages other natural gas
drilling programs similar to the Program, the effect of which is that the
Managing General Partner owes a duty of good faith to each of the
partnerships which it manages and actions taken with regard to other
partnerships may not be advantageous to the Partnership; the Managing
General Partner decides which Prospects each Partnership will acquire, the
effect of which is that the Managing General Partner could benefit, as a
result of cost savings or reduction of risk, for instance, by assigning or
not assigning and by retaining particular Prospects to the Partnership;
the Managing General Partner will act as operator and will provide
drilling and completion services to the Partnerships, for which the
Managing General Partner will be compensated (at rates competitive with
the rates charged by unaffiliated persons for similar services); the
dealer manager, an Affiliate of the Managing General Partner, will receive
commissions on the basis of the amount of proceeds raised in the offering
(some of which the dealer manager will reallow to the broker-dealers which
effected the actual sales of Units). See "Conflicts of Interest."
Unpredictable Producing Life of Wells; Uncertainty of Production. The
Managing General Partner cannot predict the life and production of any
well. The actual lives could differ from those anticipated. Sufficient
gas may not be produced for investors to receive a profit or even to
recover their initial investment.
Joint Activities with Others -- Potential Partnership Liability. The
Partnerships will usually acquire less than the full Working Interest in
Prospects and, as a result, will engage in joint activities with other
Working Interest owners. A Partnership could be held liable for the joint
activity obligations of the other Working Interest owners, such as
nonpayment of costs and liabilities arising from the actions of the
Working Interest owners. Full development of the Prospects may be
jeopardized in the event of the inability of other Working Interest owners
to pay their respective shares of Drilling and Completion Costs. See
"Proposed Activities -- Drilling and Completion Phase -- Drilling and
Operating Agreement."
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Shortage of Working Capital -- No External Sources of Funds. The
Partnership intends to utilize substantially all available capital from
this offering for the drilling and completion of wells and will have only
nominal funds available for Partnership purposes prior to such time as
there is production from Partnership well operations. The Partnership
Agreement does not permit the Partnership to borrow money as may be
required for its business. Therefore, any future requirement for
additional funding will have to come, if at all, from the Partnership's
production. There is no assurance that production will be sufficient to
provide the Partnership with necessary additional funding. See "Source of
Funds and Use of Proceeds -- Subsequent Source of Funds" and "Proposed
Activities -- Production Phase of Operations -- Expenditure of Production
Revenues."
Other Partnerships Sponsored by Managing General Partner; Possible
Competition for Prospects, Equipment, Contractors, and Personnel. During
1996 and thereafter, the Managing General Partner plans to offer interests
in other partnerships to be formed for substantially the same purposes as
those of the Partnerships. Therefore, a number of partnerships with
unexpended capital funds, including those partnerships to be formed before
and after the Partnerships, may exist at the same time. Due to
competition among partnerships for suitable prospects and availability of
equipment, contractors, and Managing General Partner personnel, the fact
that partnerships previously organized by the Managing General Partner and
its Affiliates may still be purchasing Prospects (when the Partnership is
attempting to purchase Prospects) may make more difficult the completion
of Prospect acquisition activities by a Partnership.
Purchase of Units by Managing General Partner or its Affiliates May
Assure Minimum Aggregate Subscription; Limitation on Purchases. The
Managing General Partner and its Affiliates may also purchase Units, the
effect of which may be to assure that the minimum aggregate Subscription
amount is obtained for any Partnership; however, the Managing General
Partner and its Affiliates are not obligated to purchase any Units and the
required minimum Subscription amount might not be obtained in any
Partnership. The Managing General Partner and/or its Affiliates are
permitted to purchase no more than 10% of the Units subscribed by the
Investor Partners in any Partnership. Nevertheless, not more than $50,000
of the Units purchased by the Managing General Partner and/or its
Affiliates are permitted to be applied to satisfying the $1 million
minimum requirement for any Partnership. The effect of this provision is
that at least 95% of the minimum subscription proceeds must be raised from
persons unaffiliated with the Managing General Partner, if a particular
Partnership is to satisfy the requirements to close a Partnership. Any
purchases made by the Managing General Partner and/or its Affiliates will
be purchased for investment purposes and not for resale.
Exploratory and Development Drilling; Different Degrees of Risk. Each
Partnership may drill one or more Exploratory Wells. Drilling Exploratory
Wells involves greater risks of Dry Holes and loss of the Investor
Partners' investment. Drilling Developmental Wells generally involves
less risk of Dry Holes but developmental acreage is more expensive and
subject to greater royalties and other burdens on production.
Past Experience Not Indicative of These Partnerships. Information
concerning the prior drilling experience of previous partnerships
sponsored by the Managing General Partner and its Affiliates, presented
under the caption "Prior Activities," is not indicative of the results to
be expected by these Partnerships.
Sharing of Risks of Nonproductive Operations. Under the cost and
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revenue sharing provisions of the Partnership Agreement, the Investor
Partners and the Managing General Partner may share in costs
disproportionate to their sharing of revenues. Because the Investor
Partners will bear the substantial amount of costs of acquiring, drilling
and developing the Prospects, the Investor Partners will bear the
substantial amount of costs and risks of drilling Dry Holes and marginally
productive wells.
Restrictions Upon Activities of the Investor Partners. The Investor
Partners are not authorized to participate in the management of the
Partnership business. The Partnership Agreement forbids the Investor
Partners from acting in a manner harmful to the business of the
Partnership. If an Investor Partner acts in contravention of the terms of
the Partnership Agreement, such Partner may have to pay for such losses
and such Partner may have to pay other Partners for all damages resulting
from his breach of the Partnership Agreement.
Indemnification of Additional General Partners by Managing General
Partner; Risk of Loss of Investment. The Managing General Partner has
agreed to indemnify each of the Additional General Partners for
obligations related to casualty and business losses which exceed available
insurance coverage and Partnership assets. Any successful claim of
indemnification will reduce the value of the Partnership. The value of
the investment interest of the Investor Partners would be reduced. In
such event, the Investor Partners could lose their entire investment in
the Partnership. The Managing General Partner will have no liability to
the Partnership or to any Investor Partner for any loss suffered by the
Partnership if the Managing General Partner in good faith determined that
its action was in the best interest of the Partnership and that such
action did not constitute negligence or misconduct of the Managing General
Partner. See "Summary of Partnership Agreement -- Indemnification."
Limitation of Acts Allowed by Limited Partners. Under the West Virginia
Uniform Limited Partnership Act (the "Act"), a Limited Partner will not be
liable for the obligations of a Partnership unless such person takes part
in the control of the business of the Partnership. The Partnership
Agreement states that a Limited Partner is not permitted to participate in
the control of the business of the Partnership.
Risk of Return of Limited Partner Distributions. If Limited Partners
receive a return of any part of their Capital Contributions to a
Partnership, without violation of the Partnership Agreement or the Act,
such Limited Partners will be liable to the Partnership for a period of
one year thereafter for the amount of the returned contributions. If the
return is in violation of the Partnership Agreement or the Act, the
Limited Partners will be liable to the Partnership for a period of six
years thereafter for the amount of the contribution wrongfully returned.
Financial Capability of the Managing General Partner as General Partner
of Several Partnerships; Significant Loss by Managing General Partner
Could Adversely Affect Partnership. As a result of its commitments as
general partner of several partnerships and because of the unlimited
liability of a general partner to third parties, the net worth of the
Managing General Partner is at risk of reduction. Because the Managing
General Partner is primarily responsible for the conduct of the
Partnership's affairs, a significant adverse financial reversal for the
Managing General Partner could have an adverse effect on the Partnership
and the value of the Units therein.
No Allocations or Distributions If Capital Account Deficit. The
Partnership Agreement prohibits the Investor Partners from receiving
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allocations or distributions to the extent such would create or increase
deficits in their Capital Accounts.
No Independent Underwriters. PDC Securities Incorporated, the Dealer
Manager of this offering, is an Affiliate of the Managing General Partner
and is not independent which creates a conflict of interest in its due
diligence examination and evaluation of this offering. See "Conflicts of
Interest."
Risks Pertaining to Natural Gas Investments
Speculative Nature of Well Drilling; Production Risks. Natural gas
drilling is a highly speculative activity marked by many unsuccessful
efforts. Investors must recognize the possibility that the wells drilled
may not be productive. Even those wells which are completed may not
produce enough gas to show a profit. Delays and added expenses may also
be caused by poor weather conditions affecting, among other things, the
ability to lay pipelines. In addition, ground water, various clays, lack
of porosity, and permeability may hinder, restrict or even make production
impractical or impossible. Up to 10% of the Partnership's activities may
involve exploratory wells. The likelihood of failing to find commercial
quantities of gas is relatively high in exploratory wells.
Prices of Natural Gas Quite Unstable. Global economic conditions,
political conditions, and energy conservation have created unstable
prices. The prices for domestic natural gas production have materially
declined and may remain depressed or possibly decline which would
adversely affect the Partnerships and the Investor Partners. Prices for
natural gas have been and are likely to remain extremely unstable.
Competition, Markets and Regulation. A large number of companies and
individuals engage in drilling for natural gas and there is competition
for the most desirable Leases. The sale of any natural gas found and
produced by the Partnerships will be affected by fluctuating market
conditions and regulations, including environmental standards, set by
state and federal agencies. Currently there exists a surplus of natural
gas in West Virginia, Pennsylvania, and many other areas of the United
States. The effect of this surplus may be to reduce the price the
Partnerships may receive for their gas production, or to reduce the amount
of natural gas that the Partnerships may produce and sell. See
"Competition, Markets and Regulation."
Environmental Hazards and Liabilities. There are numerous natural
hazards involved in the drilling of wells, including unexpected or unusual
formations, pressures, blowouts involving possible damages to property and
third parties, surface damages, bodily injuries, damage to and loss of
equipment, reservoir damage and loss of reserves. Uninsured liabilities
would reduce the funds available to a Partnership, may result in the loss
of Partnership properties and may create liability for Additional General
Partners. A Partnership may be subject to liability for pollution, abuses
of the environment and other similar damages. Although the Partnerships
will maintain insurance coverage in amounts the Managing General Partner
deems appropriate, it is possible that insurance coverage may be
insufficient. In that event, Partnership assets would be utilized to pay
personal injury and property damage claims and the costs of controlling
blowouts or replacing destroyed equipment rather than for additional
drilling activities.
Increases in Drilling Costs. Current economic conditions indicate that
the costs of exploration and development are increasing gradually;
however, the oil and gas industry historically has experienced periods of
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rapid cost increases from time to time, and within short periods of time.
Increases in the cost of exploration and development would affect the
ability of the Partnerships to acquire additional Leases, gas equipment,
and supplies. Increased drilling activity could lead to shortages of
equipment and material which would make timely drilling and completion of
wells impossible.
Availability of Rigs and Prospects. A substantial increase in drilling
operations in the United States could result in the decreased availability
of drilling rigs and gas field tubular goods. Also, international
developments and the possible improved economics of domestic oil and gas
exploration may influence major oil companies to increase their domestic
oil and gas exploration. Those factors may adversely affect the
operations of the Partnerships.
Financial Condition of Subcontractors. Although the Managing General
Partner will endeavor to ascertain the financial condition of
nonaffiliated subcontractors, if subcontractors fail to timely pay for
materials and services, the wells of the Partnerships could be subject to
materialmen's and workmen's liens. In that event, the Partnerships could
incur excess costs in discharging such liens.
Shut-in Wells; Delays in Production. Production from wells drilled in
areas remote from marketing facilities may be delayed until sufficient
reserves are established to justify construction of necessary pipelines
and production facilities. In addition, production from wells may be
reduced or delayed due to marketing demands which tend to be seasonal.
Wells drilled for the Partnerships may have access to only one potential
market. Local conditions including but not limited to closing businesses,
conservation, shifting population, pipeline maximum operating pressure
constraints, and development of local oversupply or deliverability
problems could halt sales from Partnership wells.
Delay in Distributions of Revenue. Distribution of revenue may be
delayed for substantial periods of time after discovery of natural gas due
to unavailability of, or delay in obtaining, necessary material for
completion of a well; reduced takes by purchasers of natural gas due to
market conditions; delays in obtaining satisfactory purchase contracts and
connections for gas wells; delays in title opinions and obtaining division
orders; and other circumstances.
Tax Status and Tax Risks
It is possible that the tax treatment currently available with respect
to natural gas exploration and production will be modified or eliminated
on a retroactive or prospective basis by additional legislative, judicial,
or administrative actions. The limited tax benefits associated with gas
exploration do not eliminate the inherent attendant risks. See "Tax
Considerations."
Partnership Classification; No IRS Ruling Sought. Tax counsel has
rendered its opinion that each Partnership will be classified for federal
income tax purposes as a partnership and not as an association taxable as
a corporation or as a "publicly traded partnership." Such opinion is not
binding on the Service or the courts and the Managing General Partner will
not request a ruling from the Service confirming the opinion of counsel.
The Service could assert that a Partnership should be classified as an
association taxable as a corporation or as a "publicly traded
partnership." If a Partnership is so classified, any income, gain, loss,
deduction, or credit of the Partnership will remain at the entity level,
and not flow through to the Investor Partners, the income of the
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Partnership will be subject to corporate tax rates at the entity level and
distributions to the Investor Partners may be considered dividend
distributions subject to federal income tax at the Investor Partners'
level. See "Tax Considerations -- General Tax Effects of Partnership
Structure."
General Partner Interests Versus Limited Partner Interests. An
investment as an Additional General Partner in a Partnership may not be
advisable for a person whose taxable income from all sources is not
recurring or is not normally subject to the higher marginal federal income
tax rates. An investment as a Limited Partner may not be advisable for a
person who does not anticipate having substantial current taxable income
from passive trade or business activities. Such a person cannot utilize
any passive losses generated by the Partnerships until he is in receipt of
passive income.
The Additional General Partners will have the right to convert their
interests into limited partnership interests, subject to certain
limitations. The Managing General Partner will convert all Units of
general partnership interest into Units of limited partnership interest
upon completion of drilling. Upon the conversion, gain will be recognized
to the extent that any liabilities of which he is considered relieved due
to the conversion exceed his adjusted basis in his Partnership interest.
Partnership income, losses, gains, and deductions allocable to any
Limited Partners will be subject to the passive activity rules whereas
those allocable to an Additional General Partner will generally not be
subject to the passive activity rules. Upon conversion of an Additional
General Partner's interest to that of a Limited Partner, subsequently
allocable income and gains will be treated as nonpassive while losses and
deductions will be subject to limitation under the passive loss rules.
See "Tax Considerations."
Tax Liabilities in Excess of Cash Distributions. Federal income tax
payable by an Investor Partner by reason of his distributive share of
Partnership taxable income for any year may exceed the cash distributed to
such Partner by the Partnership. An Investor Partner must include in his
own return for a taxable year his share of the items of the Partnership's
income, gain, profit, loss, and deductions for the year, to the extent
required under the Internal Revenue Code as then in effect, whether or not
cash proceeds are actually distributed to the Partner. For example,
income from the Partnership's sale of gas production is taxable to
Investor Partners as ordinary income subject to depletion and other
deductions; an Investor Partner's distributive share of the Partnership's
taxable income will be taxable to such Partner whether or not it is
actually distributed, for example, where Partnership income is used to
repay Partnership indebtedness.
Chance of Audits. Although the Partnerships will not be registered with
the Service as "tax shelters," it is likely that the Service will audit
each Partnership's returns. If such audits occur, tax adjustments might
be made that would increase the amount of taxes due or increase the risk
of audit of Investor Partners' individual tax returns. In addition, costs
and expenses may be incurred by a Partnership in contesting such
adjustments. The cost of responding to audits of Investor Partners' tax
returns will be borne solely by the Investor Partners whose returns are
audited. See "Tax Considerations -- Administrative Matters."
Items Not Covered by the Tax Opinion. Due to the lack of authority, or
the essentially factual nature of the question, however, tax counsel to
the Partnership, Metzger, Hollis, Gordon & Mortimer, has expressed no
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opinion as to the following: (i) whether the losses of the Partnership
will be treated as derived from "activities not engaged in for profit,"
and therefore nondeductible from other gross income, (ii) whether any of
the Partnership's properties will be entitled to percentage depletion,
(iii) whether any interest incurred by a Partner with respect to any
borrowings will be deductible or subject to limitations on deductibility,
(iv) whether the fees to be paid to the Managing General Partner and to
third parties will be deductible, and (v) the impact of an investment in
the Partnership on an Investor's alternative minimum tax.
For the reasons more fully described below, tax counsel has expressed
no opinion on: (i) the deductibility in a given year of any intangible
drilling and development costs incurred in a year prior to drilling of the
wells to which such costs relate, (ii) the availability or extent of
percentage depletion deductions to the Partners, (iii) the federal income
tax treatment of interest expense on debt incurred by investors in
connection with their acquisition of Units, (iv) the amount, if any, of
the Management Fee, the Dealer Manager's Fee and various other fees paid
to third parties, the Managing General Partner, the Operator, or their
affiliates that will be deductible or amortizable, and (v) whether an
investment in the Partnership may subject an investor to the, or increase
an investor's, alternative minimum tax.
Various of the above-referenced matters are factual in nature, and the
facts are unknown at this time. Therefore, counsel is unable to render an
opinion at this time with respect to these matters as to the tax
consequences and burdens a taxpayer will likely experience as a result of
an investment in the Partnership. The facts when they become known with
respect to the various matters referred to above will vary from taxpayer
to taxpayer and will result in different tax consequences and burdens for
individual taxpayers.
Prospective investors should recognize that an opinion of counsel merely
represents such counsel's best legal judgment under existing statutes,
judicial decisions, and administrative regulations and interpretations.
There can be no assurance, however, that some of the deductions claimed by
a Partnership will not be challenged successfully by the Service.
Working Interest Exception to the Passive Loss Limitations. Tax counsel
to the Managing General Partner has rendered its opinion that interests in
the Partnerships held by the Additional General Partners will not be
subject to the passive activity rules. However, losses arising after a
conversion to limited partnership interests will be treated as passive
and, consequently, will only be available to offset passive income.
Losses allocable to the Limited Partners will be subject to the passive
loss rules, while income so allocable will be passive except to the extent
characterized as portfolio.
Material Portion of Subscription Proceeds Not Currently Deductible. A
material portion of the Subscription proceeds of a Partnership will be
expended for cost and expense items which will not be currently deductible
for income tax purposes. See "Tax Considerations -- Transaction Fees."
Prepayment of Drilling Costs. Some drilling cost expenditures may be
made as prepayments during 1996 (with respect to Partnerships designated
as "PDC 1996-_ Limited Partnership") and 1997 (with respect to
Partnerships designated as "PDC 1997-_ Limited Partnership") for drilling
and completion operations which in large part may be performed during 1997
and 1998, respectively. All or a portion of such prepayments may be then
currently deductible by the applicable Partnership if the well to which
the prepayment relates is spudded within 90 days after December 31, 1996
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or 1997, respectively; the payment is not a mere deposit; and the payment
serves a business purpose or otherwise satisfies the clear reflection of
income rule. A Partnership could fail to satisfy the requirements for
deduction of prepaid intangible drilling and development costs. The
Service may challenge the deductibility of such prepayments. If such a
challenge were successful, such prepaid expenses would be deductible in
the tax year in which the services under the drilling contracts are
actually performed. See "Tax Considerations -- Intangible Drilling and
Development Costs Deductions."
TERMS OF THE OFFERING
General
- Up to eight limited partnerships (four in 1996, four in 1997)
- Units of general partnership interest and Units of limited
partnership interest being offered -- investor may choose
- $20,000 Units
- Minimum subscription $5,000
- Minimum partnership -- $1,000,000 in subscriptions
- Maximum partnership -- $10,000,000 in subscriptions
- Maximum aggregate subscriptions for eight partnerships --
$50,000,000
- Subscription proceeds will be placed in escrow until Partnership
funded.
An aggregate of $50,000,000 of preformation interests in a series of up
to eight limited partnerships to be formed ("PDC 1996-1997 Drilling
Program") is being offered in 2,500 Units of $20,000 per Unit to
prospective investors who meet the suitability standards set forth below.
Interests in the Program will be offered over a two-year period with
interests in the partnerships designated "PDC 1996-_ Limited Partnership"
being offered only during 1996 and interests in the partnerships
designated "PDC 1997-_ Limited Partnership" being offered only during
1997. The managing general partner of each Partnership will be Petroleum
Development Corporation, a publicly-owned Nevada corporation (the
"Managing General Partner"). The Managing General Partner in its
discretion may accept subscriptions for less than full Units. The minimum
subscription is one-quarter Unit ($5,000). In the event an investor
purchases Units on more than one occasion during the offering period of a
Partnership, the minimum purchase on each occasion is $5,000 (one-quarter
Unit). Units will not be sold to tax-exempt investors or to foreign
investors. Upon the sale of at least the minimum number of Units in a
Partnership (50 Units aggregating $1,000,000) and upon termination of the
offering of Units in that Partnership, the Managing General Partner will
form a limited partnership under the laws of West Virginia. At that time
the units of preformation general partnership interest and preformation
limited partnership interest will become Units of general partnership
interest and Units of limited partnership interest, respectively, in the
particular Partnership. There is no restriction on the composition of the
type of partnership interests with respect to any Partnership.
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If the minimum required aggregate subscription amount of $1,000,000 is
not realized in the offering of Units of any Partnership, that Partnership
will not be funded, and the Escrow Agent will promptly return all
subscription proceeds with respect to that Partnership to the respective
subscribers in full with any interest earned thereon and without any
deduction therefrom. The Managing General Partner may not complete a sale
of Units to any investor until at least five business days after the date
the investor has received a final prospectus. In addition, the Managing
General Partner will send to each investor a confirmation of the purchase.
Subscribers may elect to purchase Units as an Additional General Partner
or as a Limited Partner. Additionally, a subscriber may purchase Units of
general partnership interest and Units of limited partnership interest.
The Partnerships will be designated as PDC 1996-A Limited Partnership,
PDC 1996-B Limited Partnership, PDC 1996-C Limited Partnership, and PDC
1996-D Limited Partnership with respect to the Partnerships to be offered
during 1996 and PDC 1997-A Limited Partnership, PDC 1997-B Limited
Partnership, PDC 1997-C Limited Partnership, and PDC 1997-D Limited
Partnership with respect to the Partnerships to be offered during 1997.
The maximum Subscription of any Partnership will be the lesser of
$10,000,000 or the remaining unsold units based on the $50,000,000
aggregate registration.
The Subscription period for all Partnerships designated "PDC 1996-_
Limited Partnership" will terminate on December 31, 1996, whereas the
Subscription period for all Partnerships designated "PDC 1997-_ Limited
Partnership" will terminate on December 31, 1997, unless earlier
terminated or withdrawn by the Managing General Partner. Although the
Managing General Partner may terminate an offering of Units in any
Partnership at any time, the Managing General Partner anticipates that the
respective offering periods for PDC 1996-A Limited Partnership will
terminate on May 31, 1996, PDC 1996-B Limited Partnership will terminate
on September 13, 1996, PDC 1996-C Limited Partnership will terminate on
November 15, 1996, and PDC 1996-D Limited Partnership, will terminate on
December 31, 1996. Additionally, the Managing General Partner anticipates
that the respective offering periods for PDC 1997-A Limited Partnership,
PDC 1997-B Limited Partnership, PDC 1997-C Limited Partnership, and PDC
1997-D Limited Partnership will terminate on May 30, 1997, September 12,
1997, November 14, 1997, and December 31, 1997. The offering of any
particular Partnership may extend beyond its anticipated termination date
by not more than sixty days or be terminated earlier; however, no offering
of Partnerships designated "PDC 1996-_ Limited Partnership" or
Partnerships designated "PDC 1997-_ Limited Partnership" may extend beyond
December 31, 1996 or December 31, 1997, respectively. Except as otherwise
stated below, the offering of Units in subsequent Partnerships (PDC 1996-B
Limited Partnership, PDC 1996-C Limited Partnership or PDC 1996-D Limited
Partnership, PDC 1997-A Limited Partnership, PDC 1997-B Limited
Partnership, PDC 1997-C Limited Partnership, or PDC 1997-D Limited
Partnership, as the case may be) will not commence until the Subscription
of Units in prior Partnerships (PDC 1996-A Limited Partnership, PDC 1996-B
Limited Partnership, PDC 1996-C Limited Partnership, PDC 1996-D Limited
Partnership, PDC 1997-A Limited Partnership, PDC 1997-B Limited
Partnership or PDC 1997-C Limited Partnership, as the case may be) has
reached the minimum of at least $1,000,000 or that prior offering has
terminated. The Managing General Partner may choose to offer the Units of
PDC 1996-C Limited Partnership and PDC 1996-D Limited Partnership (or PDC
1997-C Limited Partnership and PDC 1997-D Limited Partnership) at the same
time until the offering of Units in PDC 1996-C Limited Partnership (or PDC
1997-C Limited Partnership) has been terminated, in order that investors
be allowed to diversify their investments in the two Partnerships, if they
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so choose. Once the offering with respect to a particular Partnership has
been closed, no additional Units will be offered or sold with respect to
that Partnership. The Managing General Partner may determine to terminate
the offering of Units with respect to any particular Partnership at any
time before or after the minimum Subscriptions have been obtained. At or
about the time of funding of a particular Partnership, it is anticipated
that this Prospectus will be supplemented or amended to reflect the
results of the offering of such Partnership. No operations by a
particular Partnership will commence until termination of its offering
period.
Each Partnership will be funded promptly following the termination of
its respective offering period, provided that such Partnership has
Subscriptions aggregating at least $1,000,000 (50 Units). The Managing
General Partner may accelerate or delay the funding of any particular
Partnership. However, the Managing General Partner will not delay the
funding of any Partnership beyond December 31, 1996 or December 31, 1997,
with respect to Partnerships designated "PDC 1996-_ Limited Partnership"
or "PDC 1997-_ Limited Partnership," respectively. No Units in a
Partnership will be offered or sold after the close of its offering period
and its funding. As its Capital Contribution, the Managing General
Partner will invest an amount equal to not less than 21-7/8% of the
aggregate contributions by the Investor Partners. The Managing General
Partner is obligated to pay for all Leases and tangible drilling Costs in
addition to intangible drilling costs ("IDC") in excess of the IDC paid by
the Capital Contributions of the Investor Partners with respect to each
Partnership organized; therefore, the Managing General Partner will make
such additional contributions in cash to the Partnership equal to such
additional Costs.
The Managing General Partner and/or its Affiliates may, in their sole
and absolute discretion, purchase Units at a price equal to the offering
price set forth herein, net of commissions. In such event the Managing
General Partner and/or its Affiliates will be entitled to the same ratable
interest in the Partnership as other Investors. The purchase of Units by
the Managing General Partner and/or its Affiliates may permit the
Partnership to satisfy its requirements to sell the minimum number of
Units in order to close the offering. The Managing General Partner and/or
its Affiliates have no present intention to purchase any Units; the
Managing General Partner and/or its Affiliates are not permitted to
purchase more than 10% of the Units subscribed by the Investor Partners in
any Partnership; and not more than $50,000 of any Units purchased by the
Managing General Partner and/or its Affiliates will be applied to
satisfying the $1,000,000 minimum. Any Units purchased by the Managing
General Partner and/or its Affiliates will be made for investment purposes
only and not with a view toward redistribution or resale. The Managing
General Partner and/or its Affiliates will be prohibited from voting with
respect to any Unit so purchased.
Subscriptions for Units are payable $20,000 in cash per Unit purchased
upon subscription. Subscription proceeds of each Partnership will be held
in a separate interest-bearing escrow account at PNC Bank, N.A. located at
Fifth Avenue and Wood Street, Pittsburgh, Pennsylvania 15222 (the "Escrow
Agent"), during the offering period of such Partnership. The Escrow Agent
is the owner of 10.9% of the outstanding stock of the Managing General
Partner. The Escrow Agent is required by the escrow agreement to invest
escrowed funds upon receipt and is forbidden to disburse funds except upon
deposit of checks representing at least the minimum subscriptions and upon
written instructions from the Managing General Partner and dealer manager.
At that time the Escrow Agent will disburse in accordance with such
instructions. In the event that the minimum subscriptions have not been
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collected, the Escrow Agent will promptly return the escrowed funds to the
subscribers.
As disclosed under "Risk Factors -- Special Risks of the Partnerships -
- - Irrevocable Subscriptions; Escrow of Subscription Funds," escrowed
Subscriptions of Partnerships not closed by the sixtieth day following the
anticipated offering termination date (May 31, 1996 for PDC 1996-A Limited
Partnership and September 13, 1996 for PDC 1996-B Limited Partnership; May
30, 1997 for PDC 1997-A Limited Partnership and September 12, 1997 for PDC
1997-B Limited Partnership) will be promptly returned to the respective
investor of that Partnership. If the respective offering of Units in PDC
1996-C Limited Partnership or PDC 1996-D Limited Partnership has not
closed on or before December 31, 1996 or if the respective offering of
Units in PDC 1997-C Limited Partnership or PDC 1997-D Limited Partnership
has not closed on or before December 31, 1997, the escrowed funds of that
particular Partnership will be promptly returned to those investors.
Subscriptions will not be commingled with the funds of the Managing
General Partner or its Affiliates, nor will Subscriptions be subject to
the claims of their creditors. Subscription proceeds will be invested
during the offering period only in short-term institutional investments
comprised of or secured by securities of the U.S. government. The
interest rate on the escrow account is variable and is presently 4%.
Checks for Units should be made payable to "PNC Bank, N.A. as Escrow Agent
for PDC 1996-_ Limited Partnership" (or "PNC Bank, N.A. as Escrow Agent
for PDC 1997-_ Limited Partnership," as the case may be) and should be
given to the subscriber's broker for submission to the Dealer Manager and
Escrow Agent.
The execution of the Subscription Agreement by a subscriber or in the
case of fiduciary accounts by his authorized representative constitutes a
binding offer to buy Unit(s) in a Partnership and an agreement to hold the
offer open until the Subscription is accepted or rejected by the Managing
General Partner. Once an investor subscribes for Units, he or she will
not have any revocation rights, unless otherwise provided by state law.
The Managing General Partner may refuse to accept any Subscription without
liability to the subscriber. The Managing General Partner may reject a
Subscription if, for example, the prospective investor does not satisfy
the suitability standards or if the Subscription is received after the
offering period has terminated. The execution of the Subscription
Agreement and its acceptance by the Managing General Partner also
constitute the execution of the Partnership Agreement and an agreement to
be bound by the terms thereof as a Partner, including the granting of a
special power of attorney to the Managing General Partner appointing it as
the Partner's lawful representative to make, execute, sign, swear to, and
file a Certificate of Limited Partnership and any amendment thereof,
governmental reports, certifications, contracts, and other matters.
Activation of the Partnerships
- Each Partnership will be funded following termination of offering
period.
- Each Partnership is a separate business and economic entity from each
other Partnership.
- Partnerships will be formed under West Virginia law.
Each Partnership will be formed pursuant to the Act and funded promptly
following the termination of its offering period. However, a Partnership
will not be funded with less than minimum aggregate Subscriptions of
$1,000,000. The Partnerships will not have any substantial assets or
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<PAGE>
liabilities and will not commence any drilling operations until after
their respective funding.
Each Partnership is and will be a separate and distinct business and
economic entity from each other Partnership. Thus, the Investor Partners
in one Partnership will be Partners only of that Partnership in which they
specifically subscribe and will not have any interest in any of the other
Partnerships. Therefore, they should consider and rely solely upon the
operations and success (or lack thereof) of their own Partnership in
assessing the quality of their investment. The performance of one
Partnership will not be attributable to the performance of other
Partnerships.
Upon funding of a Partnership, the Managing General Partner will deposit
the Subscription funds in interest-bearing accounts or invest such funds
in short-term highly-liquid securities where there is appropriate safety
of principal, in that Partnership's name until the funds are required for
Partnership purposes. Interest earned on amounts so deposited or invested
will be credited to the accounts of the respective Partnership whose funds
earned the interest. Interest accrued on Subscription funds prior to
closing of the offering and funding of a Partnership will be paid to the
respective Subscriber after closing.
The Managing General Partner anticipates that within 12 months following
the formation of a Partnership all Subscriptions will have been expended
or committed for Partnership operations. Any unexpended and/or
uncommitted Subscriptions at the end of such 12-month period will be
returned pro rata to the Investor Partners and the Managing General
Partner will reimburse such Partners for Organization and Offering Costs
and the Management Fee allocable to the return of capital. The term
"uncommitted capital" shall be exclusive of any amounts set aside for
necessary operating capital reserves.
The Managing General Partner will file a Certificate of Limited
Partnership and any other documents required to form the Partnerships with
the State of West Virginia and will elect for the Partnerships to be
governed by the West Virginia Uniform Limited Partnership Act. The
Managing General Partner will also take all other actions necessary to
qualify the Partnerships to do business as limited partnerships or cause
the limited partnership status of the Partnerships to be recognized in any
other jurisdiction where the Partnerships conduct business.
Types of Units
- Investor may choose to be Limited Partner or Additional General
Partner.
An Investor Partner may purchase Units in a Partnership as a Limited
Partner or as an Additional General Partner. Although income, gains,
losses, deductions, and cash distributions allocable to the Investor
Partners are generally shared pro rata based upon the amount of their
Subscriptions, there are material differences in the federal income tax
effects and the liability associated with these different types of Units.
Any income, gain, loss, or deduction attributable to Partnership
borrowing, if any, will generally be allocable to the Partners who bear
the economic risk of loss with respect to such borrowing. Further,
Additional General Partners will generally be permitted to offset
Partnership losses and deductions against income from any source. Limited
Partners will generally be allowed to offset Partnership losses and
deductions only against passive income.
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Units of partnership interest may be transferred or assigned in
accordance with Section 7.03 of the Partnership Agreement. Transferees
seeking to become substituted Partners must also meet the suitability
requirements set forth in this Prospectus. A substituted Additional
General Partner will have the same rights and responsibilities, including
unlimited liability, in the Partnership as every other Additional General
Partner. See "Tax Considerations" and "Risk Factors -- Unlimited
Liability of Additional General Partners."
An investor must indicate on the Investor Signature Page the number of
limited partnership Units or general partnership Units subscribed to and
fill in the appropriate line on the Subscription Agreement. If a
subscriber fails to indicate on the Subscription Agreement a choice
between investing as a Limited Partner or as an Additional General
Partner, the Managing General Partner will not accept the Subscription but
will promptly return the Subscription Agreement and the tendered
subscription funds to the purported Subscriber.
Limited Partners. The Limited Partners will consist of the Initial
Limited Partner, Steven R. Williams, an officer and director of the
Managing General Partner, until such time as additional limited partners
become Partners, and each investor who purchases one or more Units being
offered hereby. The liability of a Limited Partner of the Partnership for
the Partnership's debts and obligations will be limited to that Partner's
Capital Contributions, his share of Partnership assets, and the return of
any part of his Capital Contribution (a) for a period of one year
thereafter for the amount of his returned contribution (if a Limited
Partner has received the return of any part of his contribution without
violation of the Partnership Agreement or the Act), but only to the extent
necessary to discharge the Limited Partner's liabilities to creditors who
extended credit to the Partnership during the period the contribution was
held by the Partnership and (b) for a period of six years thereafter for
the amount of the contribution wrongfully returned (if a Limited Partner
has received the return of any part of his contribution in violation of
the Partnership Agreement or the Act).
General Partners. The General Partners will consist of the Managing
General Partner and each investor purchasing one or more Units of general
partnership interest (referred to herein as "Additional General
Partners"). As a general partner of a Partnership, each Additional
General Partner will be fully liable for the debts, obligations and
liabilities of the Partnership individually and as a group with all other
general partners as provided by the Act to the extent liabilities are not
satisfied from the proceeds of insurance, from the indemnification by the
Managing General Partner, or from the sale of Partnership assets. See
"Risk Factors." While the activities of the Partnership are covered by
substantial insurance policies and indemnification by the Managing General
Partner which are discussed herein, it is possible that the Additional
General Partners will incur personal liability (not covered by insurance,
Partnership assets, or indemnification) as a result of the activities of
the Partnership.
Conversion of Units by Additional General Partners
- Additional General Partners may convert to become Limited Partners
after the earlier of one year or when all wells are placed into
production.
- The Managing General Partner will convert all Units of general
partnership interest into Units of limited partnership interest upon
completion of drilling.
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<PAGE>
- If there is a material change in a Partnership's insurance coverages,
Additional General Partners may convert prior to such change.
- Liability for Investors will be limited after conversion.
Upon written notice to the Managing General Partner, and except as
provided below and in the Partnership Agreement, Additional General
Partners of a Partnership have the right to convert their interests into
limited partnership interests of that Partnership at any time after the
earlier of one year following the closing of the offering of that
Partnership and the disbursement to that Partnership of the proceeds of
the offering or when all wells are placed into production. In this regard
"production" refers to the commencement of commercial marketing of natural
gas, but does not include any spot sales of natural gas as a result of
testing procedures. In addition, the Managing General Partner will
convert all Units of general partnership interest of a particular
Partnership into Units of limited partnership interest upon completion of
drilling of that Partnership. Upon conversion they will become Limited
Partners of that Partnership. Additional General Partners may also
convert their interests into limited partnership interests at any time
within the 30 day period prior to any material change in the amount of the
Partnership's insurance coverage. Effecting conversion is subject to the
express requirements that the conversion will not cause a termination of
the Partnership for federal income tax purposes and that the Additional
General Partner provides written notice to the Managing General Partner of
such intent to convert.
Conversion of an Additional General Partner to a Limited Partner in a
particular Partnership will be effective upon the Managing General
Partner's filing an amendment to its Certificate of Limited Partnership.
The Managing General Partner is obligated to file an amendment to its
Certificate at any time during the full calendar month after receipt by
the Managing General Partner of the required notice of the Additional
General Partner, provided that the conversion will not constitute a
termination of the Partnership for tax purposes. A conversion made in
response to a material change in that Partnership's insurance coverage
will be made effective prior to the effective date of the change in
insurance coverage. After the conversion of his general partnership
interest to that of a Limited Partner, each converting Additional General
Partner will continue to have unlimited liability regarding Partnership
liabilities arising prior to the effective date of such conversion, but
will have limited liability to the same extent as Limited Partners after
conversion to Limited Partner status is effected.
The Managing General Partner is not entitled to convert its interests
into limited partnership interests. Limited Partners do not have any
right to convert their Units into Units of general partnership interest.
In the event Additional General Partners desire to convert to Limited
Partners due to a perceived increased risk of liability (e.g., loss of
insurance coverage) and such conversions would be permitted because it
would not result in termination of the Partnership for tax purposes, the
Partnership will cease drilling activities until all desired conversions
can be made.
Unit Repurchase Program
- Investors may tender Units for repurchase at any time beginning with
the third anniversary of the first cash distribution of the
particular Partnership.
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<PAGE>
- Investors may, at their election, sell their Units to the Managing
General Partner for not less than 3 times the most recent 12 months'
cash distributions from production.
- The Managing General Partner is obligated to purchase in any calendar
year such Units which aggregate up to 10% of the initial
Subscriptions, subject to its financial ability to do so and certain
opinions of counsel.
Beginning with the third anniversary of the date of the first cash
distribution of the particular Partnership, Investor Partners may tender
their Units to the Managing General Partner for repurchase. Investor
Partners are required to provide the Managing General Partner with written
notification of their intention to avail themselves of the repurchase
program. Subject to its financial ability to effect repurchases and the
opinion of counsel referred to below, each year the Managing General
Partner will offer to repurchase for cash a minimum of 10% of the Units
originally subscribed to in the particular Partnership. The Managing
General Partner's offers to purchase Units will, however, be conditioned
on the receipt of an opinion of its counsel that the consummation of such
offer will not cause the Partnership to be treated as a "publicly traded
partnership" for purposes of Code Sections 469 and 7704 and on its
determination that the repurchases of a particular Investor Partner's
Units will not result in the termination of the Partnership for federal
income tax purposes.
The Managing General Partner will not favor one particular Partnership
over another in the repurchase of Units. Such offer will be extended
equally to all interest holders participating in an individual
Partnership, excluding interests held by the Managing General Partner.
Notwithstanding the preceding sentence, if more than 10% of the Units from
a Partnership or more Units than the Managing General Partner is able to
purchase are tendered, Units will be purchased on a "first-come, first-
served" basis based on date of receipt by the Managing General Partner of
a letter of acceptance of the repurchase offer from the Investor Partner.
To the extent that the Managing General Partner is unable to repurchase
all Units tendered, due to its financial condition or because of
limitations imposed by the Code or any loan banking agreement(s) to which
the Managing General Partner may be a party, a tendering Investor Partner
will be entitled to have his Units repurchased on a "first-come, first-
served" basis, regardless of Partnership, provided that the repurchase of
a particular Investor Partner's Units will not have the effect of causing
termination of his Partnership for tax purposes or of causing the
Partnership to be treated as a "publicly traded partnership."
In order to initiate the process whereby the Managing General Partner
will repurchase the Units of Investor Partners, the Investor Partner is
required to provide the Managing General Partner written notification of
such Partner's intention to have the Managing General Partner purchase his
Units. The Managing General Partner will provide the Investor Partner a
written offer of a specified price for purchase of the particular Units
within 30 days of the Managing General Partner's receipt of the written
notification. Upon receipt of the repurchase price established by the
Managing General Partner, the Investor Partner, if in fact he elects to
accept the repurchase price, need notify the Managing General Partner in
writing that such price is acceptable. The Managing General Partner will
promptly mail the Investor Partner a check for the proceeds of the
purchase.
The minimum offer which the Managing General Partner may make will be
a cash amount equal to not less than three times cash distributions from
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<PAGE>
production of that particular Partnership for the 12 months prior to the
month preceding the date upon which the Managing General Partner has
received the written notification referred to above. The Managing General
Partner may, in its sole and absolute discretion, increase the offer for
interests tendered for sale.
Any offering price established by the Managing General Partner will not
necessarily represent the fair market value of the Units. In setting the
offering price, the Managing General Partner will consider its available
funds and its desire to acquire production as represented by the Unit and
will take into account what it perceives to be its own best interests (as
a publicly-owned company) and its shareholders. Nevertheless, each
Investor Partner is free to accept or not to accept any offering price
from the Managing General Partner; no Investor Partner is in any way
obligated to accept the Managing General Partner's offer. The Managing
General Partner will provide Investor Partners with detailed information
as to how the offer was calculated. The Managing General Partner will
also provide each interest holder with a calculation of the valuation of
his interest, based on the most recent reserve evaluation prepared by an
independent expert in accordance with SEC Regulation S-X, Article 4, Rule
4-10. This calculation will take into account the Managing General
Partner's best estimate of anticipated production declines or increases,
known price increases or decreases, operating, recompletion and plugging
costs, and other relevant factors.
To date, approximately twenty units (out of approximately 1500 eligible
units) of prior programs sponsored by the Managing General Partner have
been presented under the respective unit repurchase programs (which are
the same as that of the Partnership) for repurchase at prices ranging from
3 to 4.5 times the most recent 12 month cash distributions.
Investor Suitability
- Investment in the Units involves a high degree of risk.
- Only qualified investors may purchase Units.
- Investment is suitable only for investors having substantial
financial resources who understand the long-term nature, tax
consequences, and risk factors associated with this investment.
- Minimum requirements are $225,000 net worth, or a net worth of
$60,000 and taxable income of $60,000.
- States with more stringent requirements are set forth below.
- Transferees of Units must meet the suitability requirements set forth
herein.
It is the obligation of persons selling Units to make every reasonable
effort to assure that the Units are suitable for investors, based on the
investor's investment objectives and financial situation, regardless of
the investor's income or net worth.
Units, including fractional Units, will be sold only to an investor who
shall have a minimum net worth of $225,000 or a minimum net worth of
$60,000 and had during the last tax year or estimates that he will have
during the current tax year "taxable income" as defined in Section 63 of
the Code of at least $60,000 without regard to an investment in Units.
Net worth shall be determined exclusive of home, home furnishings and
automobiles. In addition, Units will be sold only to an investor who
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<PAGE>
makes a written representation that he is the sole and true party in
interest and that he is not purchasing for the benefit of any other person
(or that he is purchasing for another person who meets all of the
conditions set forth herein).
Additional suitability requirements are applicable to residents of
certain states where the offer and sale of Units are being made as set
forth below.
California residents generally may not transfer Units without the
consent of the California Commissioner of Corporations.
Michigan investors are not permitted to make an investment if the dollar
amount of the investment is equal to more than 10% of their net worth.
The Commissioner of Securities of Missouri classifies the Units as being
ineligible for any transactional exemption under the Missouri Uniform
Securities Act (Section 409.402(b), RSMo. 1969). Therefore, unless the
Units are again registered, the offer for sale or resale of Units by an
Investor Partner in the State of Missouri may be subject to the sanctions
of the act.
Purchasers of Limited Partnership Interest. A resident of California
who subscribes for Units of limited partnership interest must (i) have net
worth of not less than $250,000 (exclusive of home, furnishings, and
automobiles) and expect to have gross income in 1996 (with respect to
investments in the PDC 1996 designated Partnerships) or in 1997 (with
respect to the PDC 1997 designated Partnerships) of $65,000 or more, or
(ii) have net worth of not less than $500,000 (exclusive of home,
furnishings, and automobiles), or (iii) have net worth of not less than
$1,000,000, or (iv) expect to have gross income in 1996 (with respect to
investments in the PDC 1996 designated Partnerships) or in 1997 (with
respect to the PDC 1997 designated Partnerships) of not less than
$200,000.
A New Hampshire resident must have either: (i) a net worth of not less
than $250,000 (exclusive of home, furnishings, and automobiles), or (ii)
a net worth of not less than $125,000 (exclusive of home, furnishings, and
automobiles), $50,000 in taxable income.
A Michigan or North Carolina resident must have a net worth of not less
than $225,000 (exclusive of home, furnishings, and automobiles), or (b) a
net worth of not less than $60,000 (exclusive of home, furnishings, and
automobiles) and estimated 1996 (with respect to investments in the PDC
1996 designated Partnerships) or in 1997 (with respect to the PDC
1997 designated Partnerships) taxable income as defined in Section 63 of
the Internal Revenue Code of 1986 of $ 60,000 or more without regard to an
investment in a Partnership.
A Pennsylvania resident must have either: (i) a net worth of at least
$225,000 (exclusive of home, furnishings, and automobiles); or (ii) a net
worth of at least $60,000 (exclusive of home, furnishings, and
automobiles) and 1995 (for the PDC 1996 designated Partnerships; 1996 for
the PDC 1997 designated Partnerships) taxable income of or estimates that
his 1996 (for the PDC 1996 designated Partnerships; 1997 for the PDC 1997
designated Partnerships) taxable income, as defined in Section 63 of the
Code, of $60,000 or more, without regard to the investment in the Program;
or (iii) that he is purchasing in a fiduciary capacity for a person or
entity having such net worth or such taxable income. A Pennsylvania investor
is not permitted to make an investment if the dollar amount of the investment
is equal to or more than 10% that person's net worth.
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Purchasers of General Partnership Interest. A resident of Alabama,
Arizona, Arkansas, Indiana, Iowa, Kansas, Kentucky, Maine, Massachusetts,
Michigan, Minnesota, Mississippi, Missouri, New Mexico, North Carolina,
Ohio, Oklahoma, Oregon, Pennsylvania, South Dakota, Tennessee, Texas,
Vermont, or Wisconsin who subscribes for Units of general partnership
interest must represent that he (i) has an individual or joint minimum net
worth (exclusive of home, home furnishings and automobiles) with his or
her spouse of $225,000 or more, without regard to the investment in the
program and a combined minimum gross income of $100,000 ($120,000 for
Arizona residents) or more for the current year and for the two previous
years; or (ii) has an individual or joint minimum net worth with his or
her spouse in excess of $1,000,000, inclusive of home, home furnishings
and automobiles; or (iii) has an individual or joint minimum net worth
with his or her spouse in excess of $500,000, exclusive of home, home
furnishings and automobiles; or (iv) has a combined minimum gross income
excess of $200,000 in the current year and the two previous years. A
Pennsylvania investor is not permitted to make an investment if the
dollar amount of the investment is equal to or more than 10% that person's
net worth.
A resident of California who subscribes for Units of general partnership
interest must (i) have net worth of not less than $250,000 (exclusive of
home, furnishings, and automobiles) and expect to have gross income in
1996 (with respect to investments in the PDC 1996 designated Partnerships)
or in 1997 (with respect to the PDC 1997 designated Partnerships) of
$120,000 or more, or (ii) have net worth of not less than $500,000
(exclusive of home, furnishings, and automobiles), or (iii) have net worth
of not less than $1,000,000, or (iv) expect to have gross income in 1996
(with respect to investments in the PDC 1996 designated Partnerships) or
in 1997 (with respect to the PDC 1997 designated Partnerships) of not less
than $200,000.
A resident of Washington who subscribes for Units of general partnership
interest must (i) have a net worth, or a joint net worth with that
person's spouse, of not less than $1,000,000 at the time of the purchase
or (ii) have an individual income in excess of $200,000 in each of the two
most recent years or joint income with that person's spouse in excess of
$300,000 in each of those years and have a reasonable expectation of
reaching the same income level in the current year.
Miscellaneous. Transferees of Units seeking to become substituted
Partners must also meet the suitability requirements discussed above, as
well as the requirements imposed by the Partnership Agreement, including
transfers of Units by a Partner to a dependent or to a trust for the
benefit of a dependent or transfers by will, gift or by the laws of
descent and distribution.
Where any Units are purchased by an investor in a fiduciary capacity for
any other person (or for an entity in which such investor is deemed to be
a "purchaser" of the subject Units) all of the suitability standards set
forth above will be applicable to such other person.
Investors are required to execute their own subscription agreements.
The Managing General Partner will not accept any subscription agreement
that has been executed by someone other than the investor or in the case
of fiduciary accounts someone who does not have the legal power of
attorney to sign on the investor's behalf.
For details regarding how to subscribe, see "Instructions to
Subscribers" attached hereto as Appendix C.
ASSESSMENTS AND FINANCING
- 36 -
<PAGE>
- The Units of the Partnerships are not subject to assessments.
- The Partnership is not allowed to borrow funds on behalf of the
Partnership or for Partnership activities.
- Operations for the drilling of wells by the particular Partnerships
are expected to be funded through Subscription proceeds and capital
contributed to the Partnerships by the Managing General Partner.
Over the term of a Partnership, additional funds may be required
when, in the opinion of the Managing General Partner, such funds are
deemed necessary to complete that Partnership's activities.
The Managing General Partner intends to develop particular Partnership
interests in its Prospects only with the proceeds of Subscriptions and its
Capital Contributions. However, such funds may not be sufficient to fund
all such costs and it may be necessary for a Partnership to retain
Partnership revenues for the payment of such costs, or for the Managing
General Partner to advance the necessary funds to a Partnership. No wells
beyond the initial wells will be drilled. Additional development refers
to work necessary or desirable to enhance production from existing wells.
Payment for such development work will be retained from Partnership
proceeds in one of two methods:
(a) An AFE ("authority for expenditures") estimate will be prepared by
the Managing General Partner for the Partnership. The development work
will be completed by the Operator at which time the Partnership will be
billed for the work performed; or
(b) An AFE estimate will be prepared by the Managing General Partner
for the Partnership. The Partnership will retain revenues from
operations until sufficient funds have been accumulated to pay for the
development work, at which time the work will be commenced by the
Operator, and the Operator will be paid as the work is performed.
The choice of which option to use will be at the discretion of the
Managing General Partner, based on the amount of the anticipated
expenditure and the urgency of the necessary work. Generally the Managing
General Partner will elect option (a) for emergency and expenditures of
less than $10,000 and option (b) for expenditures of $10,000 and greater.
The Partnership is not permitted to borrow funds on behalf of the
Partnership or for Partnership activities. See Section 6.03(a) of the
Partnership Agreement.
Revenues allocated to the Investor Partners and applied to the payment
of capitalized costs may result in taxable income to the Investor Partners
to the extent not otherwise offset by Partnership losses and deductions.
To the extent not so offset, such revenues may result in the Investor
Partners being required to report taxable income without having received
cash distributions with which to pay the resulting tax liability. See
"Tax Considerations."
SOURCE OF FUNDS AND USE OF PROCEEDS
Source of Funds
Upon completion of the offering, the sole funds available to the
Partnerships will be the contributions of the Investor Partners
($1,000,000 ranging to $50,000,000) and the contribution of the Managing
General Partner in cash ($218,750 ranging to $10,937,500) for a total
amount of $1,218,750 if 50 Units are sold ranging to $60,937,500 if 2,500
Units are sold.
- 37 -
<PAGE>
Use of Proceeds
A total of 2,500 Units is being offered to fund up to eight Partnerships
over a two-year period. In order to fund any particular Partnership, a
minimum of 50 Units ($1,000,000) must be sold with respect to that
Partnership. The following table presents information respecting the
financing of a Partnership in three different circumstances: (1) if 500
Units ($10,000,000) are sold, the maximum number of Units which can be
sold for any Partnership, (2) if 250 Units ($5,000,000) are sold, and (3)
if the minimum 50 Units ($1,000,000) are sold. It is anticipated that
substantially all of the funds available to the Partnership will be
disbursed for the following purposes and in the following manner:
<TABLE>
<S> <S> <S> <S> <S> <S> <S>
<S>
Entity
Receiving Nature of 500 Units 250 Units 50 Units
Payment Payment Sold %(1) Sold %(1) Sold %(1)
Total
Partnership
Capital $12,187,500 100% $6,093,750 100% $1,218,750 100%
LESS: Public
Offering Expenses:
Dealer Dealer
Manager (an Manager's
Affiliate) fee 1,050,000 8.6% 525,000 8.6% 105,000 8.6%
and sales
commission (2)(3)
LESS:
Management Fee:
Managing Management
General Fee 250,000 2.1% 125,000 2.1% 25,000 2.1%
Partner
Amount Available
For Investment:
Operator Capital
(the available
Managing for opera- $10,887,500 89.3% $5,443,750 89.3% $1,088,750 89.3%
General tions (4)
Partner)
</TABLE>
____________________
(1) The percentage is based upon total Investor Partners' Capital
Contributions and the Managing General Partner's Capital Contribution.
The comparable amounts which will be utilized for each particular
purpose if all 2,500 Units were sold are as follows: capital
available for operations: $54,437,500 (89.3%); management fee:
$1,250,000 (2.1%); dealer manager's fee and sales commissions,
reimbursement of due diligence expenses, and wholesaling fees:
$5,025,000 (8.6%); and total: $60,937,500 (100%).
(2) PDC Securities Incorporated, an Affiliate of the Managing General
Partner, may reallow in whole or in part up to $5,000,000 (if 2,500
Units are sold) ranging to $100,000 (if the minimum number of Units
is sold) for sales commissions, reimbursement of due diligence
expenses, marketing support fees and other compensation payable to
other NASD-
- 38 -
<PAGE>
licensed broker-dealers in connection with the sale of the Units. PDC
Securities will receive and retain wholesaling fees equal to 0.5% of
Subscriptions; such fees will range from $5,000 if the minimum number
of Units is sold ranging to $250,000 if the maximum number of Units
is sold. Such payments will be made in cash solely on the amount of
initial Subscriptions.
(3) Organization and Offering Costs in excess of 10 1/2% of Subscriptions
will be paid by the Managing General Partner, without recourse to the
Partnership.
(4) Included herein is the Cost to the Partnerships of acquiring
Prospects, which may include Prospects acquired from the Managing
General Partner. Total lease costs of the Prospects acquired from the
Managing General Partner and unaffiliated persons will not exceed 5%
of capital available for operations.
In the event a Partnership closes for the minimum amount of
subscription units, the relative degree of risk of an investment in that
Partnership will increase in view of the lesser degree of diversification
of drilling by that Partnership. Thus, a Partnership subscribed at the
minimum level would be able to participate in fewer Prospects, thereby
increasing the effect upon the Investor Partners' investment as a result
of an unsuccessful well.
As the Partnership size increases, the number of wells drilled will
increase, thereby increasing the diversification of the Partnership and
decreasing the effect upon the Investor Partners' investment of an
unsuccessful well. However, if the Managing General Partner is unable to
secure sufficient attractive Prospects for a larger partnership, it is
possible that the average quality of the wells drilled could decline. In
addition, greater demands will be placed on the management capabilities of
the Managing General Partner in larger Partnerships.
Subsequent Source of Funds
As indicated above, it is anticipated that substantially all of the
Partnership's initial capital will be committed or expended following the
offering. The Partnership Agreement does not permit the Partnership to
borrow any funds for its activities. Consequently, any future
requirements for additional capital will have to be satisfied from
Partnership production. See "Risk Factors -- Shortage of Working
Capital."
PARTICIPATION IN COSTS AND REVENUES
Profits and losses of a particular Partnership will be allocated and
cash available for distribution will be distributed between the Managing
General Partner and Investor Partners, as follows:
<TABLE>
<S> <S> <S>
Managing
Investor Partners(1) General Partner(1)
Throughout term of
Partnership 80% 20%
</TABLE>
____________________
(1) The allocations and distributions to the Investor Partners and to the
Managing General Partner may vary during the first five years of the
Partnership in view of the Partnership's preferred cash distribution
policy.
- 39 -
<PAGE>
See "Revenues -- Preferred Cash Distributions," immediately below.
The foregoing allocation of profits and losses is an allocation of
each item of income, gain, loss, and deduction which, in the aggregate,
constitute a profit or a loss.
Revenues
Natural Gas Revenues; Sales Proceeds. Revenues from natural gas
production and gain or loss from the sale or other disposition of
productive wells, Leases and equipment will be allocated 80% to the
Investor Partners and 20% to the Managing General Partner. The revenues
to be allocated are subject to the "Preferred Cash Distributions," below.
Preferred Cash Distributions. In order that the Investor Partners
might receive in each of the first five years of Partnership operations
cash distributions equal to 10% of their Subscriptions on a cumulative
basis, the Partnership Agreement provides for a preferred cash
distribution policy for the Investor Partners by the subordination of a
portion of the Managing General Partner's allotted cash distributions.
Starting with the first distribution of revenues, after all Partnership
wells have been placed in production, the Partnership is structured to
provide preferred cash distributions to the Investor Partners so that they
might receive cash distributions equal to a minimum of 10% of their
Subscriptions per year determined on a cumulative basis. Historically
with previous partnerships sponsored by the Managing General Partner, the
first cash distribution after all partnership wells have been placed in
production has been made within approximately nine months after the
respective partnership has been funded. In order that the Investor
Partners might achieve this investment feature, the Managing General
Partner will subordinate up to 50% of its share of Partnership
distributions. The subordination will be determined on a cumulative basis
throughout the entire subordination period. If at any time during the
initial five year period of distributions from all Partnership wells the
cumulative cash returns average less than 10% on an annual basis,
subsequent distributions will be adjusted to increase the Investor
Partners' interest in distributions until such time as the cumulative
average return in 10% or the subordination period expires. There is no
assurance the Investor Partners will experience a 10% cumulative average
return. The Managing General Partner anticipates that the Investor
Partners will benefit from the subordination if the price of gas received
by the Partnership and/or the results of the Partnership's drilling
activities are unable to generate the specified return to the Investor
Partners. As a result, the Investor Partners could receive up to 90% of
Partnership distributions during the subordination period. To the extent
that preferred cash distributions are paid in any particular year, the
allocations of revenues to the Investor Partners will increase accordingly
and the allocation of revenues to the Managing General Partner will
correspondingly decrease.
Interest Income. Any interest earned on the deposit of Subscription
funds prior to the closing of the offering and funding of the respective
Partnership will be credited 100% to the Investor Partners. Interest
earned on the deposit of operating revenues and revenues from any other
sources shall be allocated and credited in the same percentages that oil
and gas revenues are then being allocated to the Investor Partners and the
Managing General Partner.
- 40 -
<PAGE>
Sale of Equipment. All revenues from sales of drilling equipment will
be allocated 100% to the Managing General Partner.
Costs
Organization and Offering Costs. Organization and Offering Costs, net
of the Dealer Manager commissions, discounts and due diligence expenses,
and wholesaling fees, of the Partnerships will be paid by the Managing
General Partner and not out of Partnership funds. The Managing General
Partner will pay all legal, accounting, printing, and filing fees
associated with the organization of the Partnerships and the offerings of
Units. The Investor Partners will pay all Dealer Manager commissions,
discounts, and due diligence reimbursement and will be allocated 100% of
these costs. However, Organization and Offering Costs in excess of 10
1/2% of Subscriptions will be allocated and charged 100% to the Managing
General Partner.
Management Fee. The nonrecurring Management Fee will be allocated
100% to the Investor Partners and 0% to the Managing General Partner.
Lease Costs, Drilling and Completion, and Gathering Line Costs. The
Costs of Leases, tangible Drilling and Completion Costs and gathering line
Costs will be allocated 0% to the Investor Partners and 100% to the
Managing General Partner.
The Managing General Partner will contribute and/or pay for all
Leases, tangible Drilling and Completion Costs, and gathering line Costs.
Intangible Drilling Costs. Intangible Drilling Costs and recapture
of Intangible Drilling Costs will be allocated 100% to the Investor
Partners and 0% to the Managing General Partner. Recapture, if any,
attributable to intangible drilling and development costs will be
allocable on the same percentage basis as intangible drilling and
development costs were allocated.
Investor Partners will pay all intangible expenses. If the Capital
Contributions of the Investor Partners are insufficient to pay the
Intangible Drilling Costs, the Managing General Partner will pay the
additional amount of such costs.
Operating Costs. Operating Costs of Partnership wells will be
allocated and charged 80% to the Investor Partners and 20% to the Managing
General Partner.
Direct Costs. Direct Costs of the Partnerships will be allocated and
charged 80% to the Investor Partners and 20% to the Managing General
Partner.
Administrative Costs. The Administrative Costs of the Partnerships
will be borne by and allocated 100% to the Managing General Partner.
The table below summarizes the participation of the Managing General
Partner and the Investor Partners, taking account of the Managing General
Partner's Capital Contribution, in the costs and revenues of the
Partnerships. See "Glossary of Terms," "Participation in Costs and
Revenues," and the Partnership Agreement, Exhibit A hereto.
- 41 -
<PAGE>
<TABLE>
<S> <S> <S>
Managing
Investor General
Partners Partner
Partnership Costs
Broker-dealer Commissions and Expenses(1) 100% 0%
Management Fee . . . . . . . . . . . . . . . . 100% 0%
Undeveloped Lease Costs. . . . . . . . . . . . 0% 100%
Drilling and Completion Costs. . . . . . . . . 80% 20%
Tangible Equipment . . . . . . . . . . . . . . 0% 100%
Intangible Drilling and Development Costs 100% 0%
Operating Costs(2) . . . . . . . . . . . . . . 80% 20%
Direct Costs(3). . . . . . . . . . . . . . . . 80% 20%
Administrative Costs . . . . . . . . . . . . . 0% 100%
Partnership Revenues
Sale of Oil and Gas Production(4). . . . . . . 80% 20%
Sale of Productive Properties(5) . . . . . . . 80% 20%
Sale of Equipment. . . . . . . . . . . . . . . 0% 100%
Sale of Undeveloped Leases . . . . . . . . . . 80% 20%
Interest Income. . . . . . . . . . . . . . . . 80% 20%
</TABLE>
(1) Organization and Offering Costs, net of the Dealer Manager
commissions, discounts, due diligence expenses, and wholesaling
fees, of the Partnerships will be paid by the Managing General
Partner and not from Partnership funds. In addition, Organization
and Offering Costs in excess of 10 1/2% of Subscriptions will be
paid by the Managing General Partner, without recourse to the
Partnerships.
(2) Represents Operating Costs incurred after the completion of
productive wells, including monthly per-well charges paid to the
Managing General Partner.
(3) The Managing General Partner will receive monthly reimbursement from
the Partnerships for their Direct Costs incurred by the Managing
General Partner on behalf of the Partnerships.
(4) See "Participation in Costs and Revenues -- Revenues -- Preferred
Cash Distributions."
(5) In the event of the sale or other disposition of a productive well,
a Lease upon which such well is situated, or any equipment related
to any such Lease or well, the gain from such sale or disposition
shall be allocated and credited to the Partners as oil and gas
revenues are allocated. The term "proceeds" above does not include
revenues from a royalty, overriding royalty, Lease interest
reserved, or other promotional consideration reserved by a
Partnership in connection with any sale or disposition, which
revenues shall be allocated to the Investor Partners and the
Managing General Partner in the same percentages that oil and gas
revenues are allocated.
The Managing General Partner estimates that Direct Costs allocable to
the Investor Partners for the initial 12 months of their operations will
- 42 -
<PAGE>
be approximately $8,000 if minimum Subscriptions ($1,000,000) are received
(representing 0.7% of aggregate Partnership capital); and approximately
$88,000 if maximum Subscriptions ($50,000,000) are received (representing
0.2% of aggregate Partnership capital). The following table sets forth
the components of these estimated charges to the Investor Partners during
the first year after a Partnership is formed, assuming the minimum and
maximum Subscriptions are obtained:
<TABLE>
<S> <S> <S>
Minimum Maximum
Subscriptions Subscriptions
(50 Units) (2,500 Units)
Administrative Costs(1). . . . . . . . . . . . . $ -0- $ -0-
Total Administrative Costs . . . . . . . $ -0- $ -0-
Direct Costs:
Audit and Tax Preparation. . . . . . . . . . $5,000 $40,000
Independent Engineering Reports. . . . . . . 2,000 36,000
Materials, Supplies and Other. . . . . . . . 1,000 12,000
Total Direct Costs . . . . . . . . . . . $8,000 $88,000
</TABLE>
___________________
(1) The Managing General Partner will bear all Administrative Costs of
the Partnerships; however, the financial statements of the
Partnerships will reflect these costs, since generally accepted
accounting principles require that all costs of doing business be
included in the historical financial statements.
The following table presents for each partnership formed by the
Managing General Partner in the last three years the dollar amount of
direct costs and administrative costs incurred by the particular
partnership in each year and the percentage of subscriptions raised
reflected thereby.
<TABLE>
<S> <S> <S> <S> <S> <S> <S>
Direct Costs
1992 1993 1994
Partnership % of % of % of
Name Amount Subscrip- Amount Subscrip- Amount Subscrip-
tions tions tions
PDC 1990-A 6,338 0.45% 6,114 0.43% 7,068 0.50%
PDC 1990-B 8,150 0.37% 9,075 0.41% 7,781 0.35%
PDC 1990-C 10,933 0.31% 11,350 0.33% 9,397 0.27%
PDC 1990-D 12,380 0.33% 12,080 0.33% 10,614 0.29%
PDC 1991-A 18,838 0.69% 9,249 0.34% 8,182 0.30%
PDC 1991-B 7,835 0.42% 6,378 0.34% 6,556 0.35%
PDC 1991-C 10,214 0.37% 10,525 0.38% 7,399 0.27%
PDC 1991-D 14,318 0.27% 23,708 0.45% 11,784 0.22%
PDC 1992-A 17,009 0.58% 7,127 0.25% 7,198 0.25%
PDC 1992-B 17,170 0.58% 13,069 0.44% 7,314 0.25%
PDC 1992-C 30,401 0.48% 18,228 0.29% 14,668 0.23%
PDC 1993-A 14,219 0.47% 9,715 0.32% 9,866 0.33%
PDC 1993-B - - 15,185 0.62% 8,787 0.36%
PDC 1993-C - - 16,235 0.53% 9,130 0.30%
PDC 1993-D - - 16,066 0.55% 9,245 0.32%
PDC 1993-E - - 22,947 0.31% 17,113 0.23%
PDC 1994-A - - - - 10,622 0.52%
- 43 -
<PAGE>
PDC 1994-B - - - - 11,950 0.44%
PDC 1994-C - - - - 11,750 0.50%
PDC 1994-D - - - - 12,750 0.17%
PDC 1995-A(1) - - - - - -
PDC 1995-B(2) - - - - - -
PDC 1995-C(3) - - - - - -
Administrative Costs
1992 1993 1994
Partnership % of % of % of
Name Amount Subscrip- Amount Subscrip- Amount Subscrip-
tions tions tions
PDC 1990-A $ 0 0.00% $ 0 0.00% $ 0 0.00%
PDC 1990-B 0 0.00% 0 0.00% 0 0.00%
PDC 1990-C 0 0.00% 0 0.00% 0 0.00%
PDC 1990-D 0 0.00% 0 0.00% 0 0.00%
PDC 1991-A 0 0.00% 0 0.00% 0 0.00%
PDC 1991-B 0 0.00% 0 0.00% 0 0.00%
PDC 1991-C 0 0.00% 0 0.00% 0 0.00%
PDC 1991-D 0 0.00% 0 0.00% 0 0.00%
PDC 1992-A 0 0.00% 0 0.00% 0 0.00%
PDC 1992-B 0 0.00% 0 0.00% 0 0.00%
PDC 1992-C 0 0.00% 0 0.00% 0 0.00%
PDC 1993-A - - 0 0.00% 0 0.00%
PDC 1993-B - - 0 0.00% 0 0.00%
PDC 1993-C - - 0 0.00% 0 0.00%
PDC 1993-D - - 0 0.00% 0 0.00%
PDC 1993-E - - 0 0.00% 0 0.00%
PDC 1994-A - - - - 0 0.00%
PDC 1994-B - - - - 0 0.00%
PDC 1994-C - - - - 0 0.00%
PDC 1994-D - - - - 0 0.00%
PDC 1995-A(1) - - - - - -
PDC 1995-B(2) - - - - - -
PDC 1995-C(3) - - - - - -
</TABLE>
___________________
(1) Partnership funded in May 1995.
(2) Partnership funded in September 1995.
(3) Partnership funded in November 1995.
Allocations Among Investor Partners; Deficit Capital Account Balances
The revenues and costs of a Partnership allocated to the Investor
Partners will be allocated among them in the proportion in which the
amount of each Investor Partner's Capital Contribution bears to the
aggregate of the Capital Contributions of all Investor Partners in the
Partnership.
To avoid the requirement of restoring a deficit Capital Account
balance, no losses will be allocated to an Investor Partner to the extent
such allocation would create or increase a deficit in the Capital Account
(adjusted for certain liabilities, as provided in the Partnership
Agreement).
Cash Distribution Policy
- 44 -
<PAGE>
- Distributions of Partnership cash are planned to be made on a monthly
basis, but will be made no less often than quarterly, to the extent
there are funds available for distribution.
- Cash distributions will be made 80% to the Investor Partners and 20%
to the Managing General Partner throughout the term of the
Partnership, but may increase for Investor Partners in view of the
preferred cash distribution policy.
- The level or amounts of cash distributions from the Program cannot
presently be predicted.
The Managing General Partner intends to distribute substantially all of
the Partnerships' available cash flow on a monthly basis; however, the
Managing General Partner will review the accounts of each Partnership at
least quarterly for the purpose of determining the Distributable Cash
available for distribution. The ability of the Partnerships to make or
sustain a constant level of cash distributions will depend upon numerous
factors. No assurance can be given that any level of cash distributions
to the Investor Partners will be attained, that cash distributions will
equal or approximate cash distributions made to investors in prior
drilling programs sponsored by the Managing General Partner or its
Affiliates, or that any level of cash distributions can be maintained.
See "Prior Activities."
In general, the volume of production from producing properties declines
with the passage of time. The cash flow generated by each Partnership's
activities and the amounts available for distribution to a Partnership's
respective Partners will, therefore, decline in the absence of significant
increases in the prices that the Partnerships receive for their respective
oil and gas production, or significant increases in the production of oil
and gas from Prospects resulting from the successful additional
development of such Prospects.
In general, cash distributions will be made 80% to the Investor Partners
and 20% to the Managing General Partner throughout the term of the
Partnership. However, Investor Partners will be entitled to receive
preferred cash distributions so that their cash distributions per year
might equal a minimum of 10% of the Subscriptions on a cumulative basis
for the first five years of Partnership well operations. The Managing
General Partner will subordinate up to 50% of its share of Partnership
distributions during the five year subordination period. See "Revenues --
Preferred Cash Distributions," above. Cash will be distributed to the
Managing General Partner and Investor Partners as a return on capital in
the same proportion as their interest in the net income of the
Partnership. However, no Investor Partner will receive distributions to
the extent such would create or increase a deficit in that Partner's
Capital Account.
For a fuller discussion of Capital Accounts and tax allocations, see
"Tax Considerations -- Partnership Allocations."
Termination
Upon termination and final liquidation of a Partnership, the assets of
the Partnership will be distributed to the Partners based upon their
Capital Account balances. If the Managing General Partner has a deficit
in its Capital Account, it will be required to restore such deficit;
however, no Investor Partner will be obligated to restore his deficit, if
any.
- 45 -
<PAGE>
Amendment of Partnership Allocation Provisions
- The Managing General Partner is allowed to amend the Partnership
Agreement without investor approval, if necessary for partnership
allocations to be recognized for federal tax purposes.
The Managing General Partner is authorized to amend the Partnership
Agreement, if, in its sole discretion based on advice from its legal
counsel or accountants, an amendment to revise the cost and revenue
allocations is required for such allocations to be recognized for federal
income tax purposes either because of the promulgation of Treasury
Regulations or other developments in the tax law. Any new allocation
provisions provided by an amendment are required to be made in a manner
that would result in the most favorable aggregate consequences to the
Investor Partners as nearly as possible consistent with the original
allocations described herein. See Section 11.09 of the Partnership
Agreement.
COMPENSATION TO THE MANAGING GENERAL PARTNER AND AFFILIATES
The following is a tabular presentation of the items of compensation
discussed more fully below:
<TABLE>
<S> <S> <S>
Recipient Form of Compensation Amount
Managing General Partnership interest 20% interest(1)
Partner
Managing General Management fee 2.5% of Subscriptions
Partner (nonrecurring fee)(2)
Managing General Sale of Leases to Cost, or fair market
Partner Partnership value if materially
less than Cost(3)
Managing General Contract drilling rat Competitive industry
Partner rates(3)
Managing General Operator's Per-Well C $300 per well per
Partner month
Managing General Direct Costs Cost(3)
Partner
Managing General Payment for equipment Competitive prices(3)
Partner and supplies and other se
Affiliates
Affiliate Brokerage sales comm- 10.5% of Subscriptions
ission reimbursement $105,000 ranging to
of due diligence and $5.25 million(4)
marketing support
expenses; wholesaling
fees
</TABLE>
_____________________
(1) The Managing General Partner will contribute to each Partnership an
amount equal to at least 21-7/8% of the aggregate contributions of
- 46 -
<PAGE>
the Investor Partners. The Managing General Partner's share of
operating profits in each Partnership will be 20%. The interests of
the Managing General Partner and the Investor Partners may vary in view
of the preferred cash distribution policy, discussed above.
(2) The one-time fee will range from $25,000 if the minimum number of
Units is sold to $1,250,000 if the maximum number of Units is sold.
(3) Cannot be quantified at the present time.
(4) PDC Securities Incorporated, an Affiliate of the Managing General
Partner, will receive as Dealer Manager of the offering sales
commissions, reimbursement of due diligence and marketing support
expenses and wholesaling fees payable from the Subscriptions of the
Investor Partners of $5,250,000 if the maximum number of Units is
sold ranging to $105,000 if the minimum number of Units is sold.
PDC Securities Incorporated may, as Dealer Manager, reallow such
commissions and due diligence and marketing support expenses in
whole or in part to NASD licensed broker-dealers for sale of the
Units, reimbursement of due diligence and marketing support
expenses, and other compensation, but will retain the wholesaling
fees of 0.5% of Subscriptions, ranging from $250,000 if the maximum
number of Units is sold to $5,000 if the minimum number of Units is
sold.
For a tabular presentation of payments to the Managing General Partner
and Affiliates made by previous partnerships sponsored by the Managing
General Partner, see "Conflicts of Interest -- Certain Transactions,"
below. The categories of compensation set forth above are comparable to
the corresponding categories of compensation for other partnerships
sponsored by the Managing General Partner disclosed in the "Certain
Transactions" table below, except with respect to the management fee which
was not a feature of the 1993 partnerships sponsored by the Managing
General Partner.
Upon completion of the offering with respect to each Partnership and
upon funding of that Partnership, the Managing General Partner will
receive a one-time Management Fee of 2.5% of total contributions of the
Investor Partners to the Partnership, an amount equal to $25,000 if the
minimum number of Units is sold ranging to $1,250,000 if the maximum
number of Units is sold. Since a maximum of $10 million of Units can be
sold in any individual Partnership, the maximum amount of the Management
Fee with respect to any individual Partnership would be $250,000.
The Managing General Partner will be reimbursed for all documented out-
of-pocket expenses incurred on behalf of the Partnership; however, there
will be no reimbursement of Administrative Costs.
The Managing General Partner will sell (at the lower of fair market
value on the date of purchase or the Managing General Partner's Cost of
such Prospects) sufficient undeveloped Prospects to the Partnership to
drill the Partnership's wells. Fair market value for Leases and Prospects
transferred from the Managing General Partner's inventory will be based on
the Cost at which similarly situated Leases and Prospects are available or
traded from or between other unaffiliated companies operating in the same
geographic area. The Cost of the Prospects will include a portion of the
Managing General Partner's reasonable, necessary and actual expenses for
geological, geophysical, engineering, interest expense, drafting, legal,
and other like services allocated to the Partnership's properties. The
Managing General Partner will not retain any overriding royalty for
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<PAGE>
itself from such Prospects (see "Proposed Activities -- Acquisition of
Prospects").
Each Partnership will enter into a drilling contract with the Managing
General Partner to drill and complete Partnership wells. The Managing
General Partner intends to use certain of its own personnel and equipment
during the drilling and completion phase of operations. These services
will be billed at rates not to exceed those charged for similar services
and equipment by other non-affiliated operators in the Partnership area of
operations. To the extent that the contract prices exceed the Managing
General Partner's actual costs of drilling and completion, the Managing
General Partner will be deemed to have received compensation. The amount
of compensation which the Managing General Partner could earn as a result
of these arrangements is dependent upon many factors, including the actual
cost of wells and the number of wells drilled. The Managing General
Partner estimates that it would need to drill approximately 50-60 wells to
absorb fully existing technical, supervisory, and management costs.
The Partnership will pay the Managing General Partner, as Operator for
drilling and completing the Partnership's wells, for each well completed
and placed into production a fee based upon the depth of the well at its
deepest penetration. For each well which the Partnership elects to
complete, the fee will be an amount equal to $60 per foot for the first
2,200 feet of well depth plus $16 per foot for each additional foot below
2,200 feet to the deepest penetration of the well, plus the actual extra
completion costs of zones completed in excess of the cost of the first
zone and the actual costs for directional drilling services, if required.
For each well which the Partnership elects not to complete, the
Partnership will pay the Managing General Partner as Operator an amount
equal to $33 per foot for the first 2,200 feet of well depth plus $9 per
foot for each additional foot below 2,200 feet to the deepest penetration
of the well plus the actual costs for directional drilling services, if
required. In the event the foregoing rates exceed competitive rates
available from other persons in the area engaged in the business of
providing comparable services or equipment, the foregoing rates will be
adjusted to an amount equal to that competitive rate, but not less than
the Cost of providing such services or equipment. In the event that the
competitive industry rates in the area and the costs of the Managing
General Partner in providing these drilling and completion services are in
excess of the Managing General Partner's contract drilling and completion
rates, the Managing General Partner will be bound by contract with the
Partnership to furnish the contracted services at the contract rates. The
Managing General Partner reviews on an ongoing basis the rates of
unaffiliated driller/operators to determine competitive rates in the
geographic area. Rates will be adjusted at the commencement of drilling
operations of each partnership formed, but no less frequently than semi-
annually. Rates will be comparable to those charged by other operators in
the prospect area for equivalent services. Comparable rates from a
minimum of two other unaffiliated operators will be acquired from one of
the following sources: offering memoranda or prospectuses for private or
public drilling programs, quoted rates, or competitive bids. In utilizing
outside contractors for drilling and completion operations (rather than
performing these services itself), the Managing General Partner will
receive an overhead payment for services as defined in the Copas
Accounting Procedure - Joint Operations equal to the most recently
published average monthly drilling overhead rate for gas wells in the
Appalachians as published by Ernst & Young in their Survey of Combined
Fixed Rate Overhead Charges for Oil and Gas Producers, and actual cost for
any direct costs associated with drilling and completion operations. That
monthly overhead rate is currently $3,387 per well per month for wells up
to 5,000 feet in depth and $4,904 per well per month for wells 5,000 feet
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<PAGE>
to 10,000 feet in depth. The total cost per well for wells drilled by
unaffiliated operators, including direct and overhead charges, may exceed
the footage rates listed in this prospectus.
During the production phase of operations, the Operator will receive a
monthly fee of $225 per well for operations and field supervision and $75
per well for accounting, engineering, management, and general and
administrative expenses for producing wells. Non-routine operations will
be billed to the Partnership at their Costs. See "Proposed Activities --
Drilling and Completion Phase -- Drilling and Operating Agreement."
The Partnerships will reimburse the Managing General Partner for Direct
Costs incurred by the Managing General Partner on behalf of the
Partnerships.
The Managing General Partner and its Affiliates may enter into other
transactions with the Partnerships for services, supplies and equipment,
and will be entitled to compensation at competitive prices and terms as
determined by reference to charges of unaffiliated companies providing
similar services, supplies and equipment. See "Conflicts of Interest."
PDC Securities Incorporated, an Affiliate of the Managing General
Partner, will receive as sales commissions, for reimbursement of due
diligence and marketing support expenses and wholesaling fees $5,250 ,000
if the maximum number of Units is sold ranging to $105,000 if the minimum
number of Units is sold. PDC Securities Incorporated may, as Dealer
Manager, reallow such sales commissions and due diligence and marketing
support expenses in whole or in part to NASD licensed broker-dealers for
sale of the Units, reimbursement of due diligence and marketing support
expenses, and other compensation, but will retain the wholesaling fees of
$5,000 ranging to $250,000.
PROPOSED ACTIVITIES
Introduction
- The primary purpose of the Partnerships will be drilling,
completing, and producing gas from development wells.
- Limited exploratory activities are allowed.
- Partnerships will acquire between 51% and 100% of the Working
Interest of each Prospect, subject to royalty interests.
- Each Partnership will be a separate business entity.
- Investors in one Partnership will have no interest in any of the
other Partnerships.
The Partnerships will be formed to drill, complete, own and operate
natural gas wells in West Virginia, Ohio and Pennsylvania. The Managing
General Partner may conduct Partnership operations in New York, Kentucky,
Michigan and/or Illinois as it may deem advisable. The Partnerships intend
to apply all of the Capital Contributions available for participation in
drilling and completion activities to comparatively lower risk Development
Wells but may apply up to 10% to comparatively higher risk Exploratory Wells.
Risks will be spread to a limited extent by participating in drilling
operations on a number of different Prospects. Until the amount of funds
to be available for a Partnership's drilling activities is determined, the
precise number of Prospects cannot be determined and the drilling budget
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cannot be formulated. The Managing General Partner has no authority to
engage in any Roll-Up without the approval of at least 66 2/3% in interest
of the Investor Partners. See "Glossary of Terms" for the definition of
"Roll-Up" and Section 5.07(m) of the Partnership Agreement.
The Partnership's principal business objectives will be:
(1) to preserve and protect the Partnership capital by investing in
eight or more natural gas wells to provide diversification and to reduce
the adverse impact of dry holes and substandard wells;
(2) to provide tax deductions for the Investor Partners in the year
of their investment in the Partnership equal to 87-89.5% of the investor's
investment. For a one Unit investment of $20,000, a deduction of $17,400
- - $17,900 will be generated, which could be used against ordinary income
by Additional General Partners and against passive income by Limited
Partners.
(3) to generate cash flow to the Investor Partners from the sale of
natural gas commencing within six months from the closing date of the
Partnership; to provide monthly cash distributions so that the Investor
Partners will receive cash distributions equal to a minimum of 10% of
their Subscriptions on a cumulative basis for each of the first five years
of Partnership life after the initial cash distribution;
(4) to develop long-lived natural gas reserve in areas where the
average economic life of successful wells is expected to be twenty years
or more; and
(5) to distribute investor K-1 tax information during the first week
of February of each year.
The Investor Partners should be aware that distributions after the
first twelve months of distributions will decrease due to the declining
rate of production from wells. Changes in gas prices will decrease or
increase cash distributions. Distributions will be partially sheltered by
the percentage depletion allowance. See "Risk Factors -- Special Risks of
the Partnerships," "-- Risks Pertaining to Oil and Gas Investments," and
"-- Tax Status and Tax Risks," "Prior Activities," and "Tax Considerations
- -- Summary of Conclusions," "-- Intangible Drilling and Development
Costs," "-- Depletion Deduction," "--Partnership Distributions," and "--
Partnership Allocations."
The attainment of the Partnership's business objectives will depend
upon many factors, including the ability of the Managing General Partner
to select productive Prospects, the drilling and completion of wells in an
economical manner, the successful management of such Prospects, the level
of natural gas prices in the future, the degree of governmental regulation
over the production and sale of natural gas, the future economic
conditions in the United States (and the world), and changes in the
Internal Revenue Code. Accordingly, there can be no assurance that the
Partnership will achieve its business objectives. Moreover, because each
Partnership will constitute a separate and distinct business and economic
entity from each other Partnership, the degree to which the business
objectives are achieved will vary among the Partnerships.
Various of the activities and policies of the Partnership discussed
throughout this section and elsewhere in the prospectus are defined in and
governed by the Partnership Agreement (the amendment of which requires the
affirmative vote of a majority of the then outstanding Units), including
that at least 90% of the net offering proceeds will be used to drill
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<PAGE>
Development Wells; the requirements relating to the acquisition of
Prospects and the payment of royalties; the amount of the Managing General
Partner's Capital Contribution to the Partnership; the guidelines with
respect to well pricing and the cost of services furnished by the Managing
General Partner and/or Affiliates; the states where the Partnership's
wells will be drilled; assessment and borrowing policies; voting rights of
Investor Partners; the term of the Partnership; and compensation of the
Managing General Partner. Other policies and restrictions upon the
activities of the Managing General Partner and the Partnership are not set
forth in the Partnership Agreement, but instead reflect the current
intention of the Managing General Partner and thus are subject to change
at its discretion. For these later activities, the Managing General
Partner, in making a change, will utilize its reasonable business judgment
as manager of the Partnership and will exercise its judgment consistent
with its obligations as a fiduciary to the Investor Partners.
Upon the successful completion of the offering, the Partnership will
effect the following transactions, each of which is more fully described
below:
(a) The Managing General Partner will assign to the Partnership
between 51% and 100% of the Working Interest in the Prospects (although
the first and last wells of the Partnership may be less than a 51%
interest); and
(b) The Partnership will enter into a drilling and operating
agreement with the Managing General Partner or with unaffiliated persons
as Operator, providing (i) for the drilling and completion of Partnership
wells and (ii) for the subsequent supervision of field operations with
respect to each producing well.
Drilling Policy
- Most wells will be direct offsets to producing wells.
Each Partnership will invest in a number of Prospects, consistent with
the objective of maintaining a meaningful interest in the wells to be
drilled. The Partnerships will not acquire any interest in currently or
formerly producing gas wells. Most wells to be drilled by the
Partnerships will be direct offsets to producing wells ("proved
undeveloped prospects"). Therefore, it is unlikely that a well on a
Prospect will have the effect of proving up any additional acreage outside
of the Prospect. For this reason, the Partnerships are expected to
acquire only spacing units on which wells are to be drilled without also
acquiring any surrounding acreage. Nevertheless, if drilling on a
Partnership Prospect proves up an adjoining spacing unit owned by the
Managing General Partner, or if there is reliable evidence that there
would be material drainage of a Partnership Prospect by an adjoining
spacing unit in which the Managing General Partner owns an interest, the
Managing General Partner will assign to the Partnership a proportionate
interest in such spacing unit.
Acquisition of Undeveloped Prospects
- The Managing General Partner will select undeveloped Prospects.
- No Prospects have yet been selected for any of the Partnerships.
- Selection of Prospects for a Partnership will occur after that
Partnership has been funded.
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<PAGE>
- At least 90% of Prospects will be development wells.
- Prospects will be acquired by the Partnerships at the lesser of Cost
or fair market value.
- Average royalty and overriding royalty burden will not exceed
16.125%.
- The Managing General Partner will not retain overriding royalty
interests.
The Managing General Partner will select undeveloped Prospects
sufficient to drill the Partnerships' wells. No Prospects have been pre-
selected by the Managing General Partner. Most Prospects to be selected
for the Partnerships are expected to be single well proved undeveloped
prospects. A Prospect may be generally defined as a contiguous oil and
gas leasehold estate, or lesser interest therein, upon which drilling
operations may be conducted.
Depending on its attributes, a Prospect may be characterized as an
"exploratory" or "development" site. Generally speaking, exploratory
drilling involves the conduct of drilling operations in search of a new
and yet undiscovered pool of oil and gas (or, alternatively, drilling
within a discovered pool with the hope of greatly extending the limits of
such pool), whereas development drilling involves drilling to a known
producing formation in a previously discovered field.
The Partnership intends to conduct development drilling operations in
one or more of the following areas: North Central West Virginia to
develop Benson, Riley and Alexander Formations; Southeastern Ohio to
develop Clinton and Medina Formations; Southern West Virginia to develop
Ravencliff through Gordon Formations as well as the Devonian Shale;
Southern and Central Pennsylvania to develop Upper Mississippian through
Upper Devonian Reservoirs, and western Pennsylvania to develop the Medina
and Whirlpool reservoirs. The Managing General Partner reserves the right
to conduct Partnership operations in New York, Kentucky, Michigan, and/or
Illinois and/or to such other formations as it may, in its sole and absolute
discretion, deem advisable, provided that such locations and/or formations
are, in the Managing General Partner's opinion, of comparable quality and
character to those described herein.
Wells in the intended area of operations are usually given a fracture
treatment in which fluids are pumped into the potential zone in an attempt
to create additional fractures and widen present fractures. It is
anticipated that gas will be produced from the subject wells, although
there could be some oil and brine production.
The Prospects will be acquired pursuant to an arrangement whereby the
Partnership will acquire between 51% and 100% of the Working Interest,
subject to landowners' royalty interests and other royalty interests
payable to unaffiliated third parties in varying amounts, provided that
the weighted average for all Prospects of a particular Partnership will
not exceed 16.125%. In its discretion the Managing General Partner may
acquire less than 51% of the Working Interest with respect to the first
and last wells drilled. The Partnership Agreement forbids the Managing
General Partner or any Affiliate from acquiring or retaining any
overriding royalty interest in the Partnership's interest in the
Prospects. The Partnerships will generally acquire less than 100% of the
Working Interest in each Prospect in which they participate. In order to
comply with certain conditions for the treatment of Additional General
Partners' interests in the Partnership as not passive activities (and
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<PAGE>
thereby not subjecting the Additional General Partners to limitation on
the deduction of Partnership losses attributable to such Additional
General Partners to income from passive activities), the Managing General
Partner has represented that the Partnerships will acquire and hold only
operating mineral interests and that none of the Partnership's revenues
will be from non-working interests. The Managing General Partner, for its
sole benefit, may sell or otherwise dispose of Prospect interests not
acquired by the Partnerships or may retain a Working Interest in such
Prospects and participate in the drilling and development of the Prospect
on the same basis as the Partnerships.
In acquiring interests in Leases, the Partnerships may pay such
consideration and make such contractual commitments and agreements as the
Managing General Partner deems fair, reasonable and appropriate. While it
is expected that a substantial portion of the Leases and interest therein
to be developed by the Partnerships will be acquired by assignment from
the Managing General Partner, the Partnerships may also purchase Leases
directly from unaffiliated persons. All Leases which are transferred to
the Partnerships from the Managing General Partner will be transferred at
its Cost, unless the Managing General Partner has reason to believe that
Cost is materially more than the fair market value of such property in
which case the price will not exceed the fair market value of such
property. Total lease costs of Prospects acquired from the Managing
General Partner and unaffiliated persons will not exceed 5% of total
capital available for operations. The Managing General Partner will
obtain an appraisal from a qualified independent expert with respect to
sales of properties of the Managing General Partner and its Affiliates to
the Partnerships.
The actual number, identity and percentage of Working Interests or
other interests in Prospects to be acquired by the Partnerships will
depend upon, among other things, the total amount of Capital Contributions
to a Partnership, the latest geological and geophysical data, potential
title or spacing problems, availability and price of drilling services,
tubular goods and services, approvals by Federal and state departments or
agencies, agreements with other Working Interest owners in the Prospects,
farm-ins, and continuing review of other Prospects that may be available.
Title to Properties
- Record title to Leases will be held in the name of the Partnership.
Prior to the drilling of any Partnership well, the Managing General
Partner will assign the Partnership interest in the Lease to the
Partnership. Leases acquired by each Partnership may initially and
temporarily be held in the name of the Managing General Partner, as
nominee, to facilitate joint-owner operations and the acquisition of
properties. The existence of the unrecorded assignments from the record
owner will indicate that the Leases are being held for the benefit of each
particular Partnership and that the Leases are not subject to debts,
obligations or liabilities of the record owner; however, such unrecorded
assignments may not fully protect the Partnerships from the claims of
creditors of the Managing General Partner.
Investor Partners must rely on the Managing General Partner to use its
best judgment to obtain appropriate title to Leases. Provisions of the
Partnership Agreement relieve the Managing General Partner from any
mistakes of judgment with respect to the waiver of title defects. The
Managing General Partner will take such steps as it deems necessary to
assure that title to Leases is acceptable for purposes of the
Partnerships. The Managing General Partner is free, however, to use its
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<PAGE>
own judgment in waiving title requirements and will not be liable for any
failure of title to leases transferred to the Partnerships. Further,
neither the Managing General Partner nor its Affiliates will make any
warranties as to the validity or merchantability of titles to any Leases
to be acquired by the Partnerships.
PDC Prospects
It is anticipated that all prospects will be evaluated by PDC's three
geologists (see "Management--Petroleum Development Corporation" for their
resumes), utilizing data provided by PDC's library of over 10,000 well
logs, production records from PDC's and others' wells, and such other
information as may be available and useful. Specific criteria for
prospects election vary depending upon well depth and estimated cost;
however, generally prospects are selected which are estimated to generate
after-tax pay back to investors in a four-to six-year time period based on
historical production from similar formations. The stratigraphic nature
of the prospects in the area is best developed by subsurface mapping based
on data from surrounding wells. As a result, nearly all wells drilled by
the Partnership will be direct offsets to existing producing wells, at a
distance of about 1,500 feet. Where multiple zone potential exists, as it
frequently does in the proposed area of operations, the geologists attempt
to optimize well locations to create wells with two or more productive
horizons.
As of September 30, 1995, PDC had acreage available as listed in the
following table within the prospect area.
<TABLE>
<S> <S> <S>
No.of
County Leases Acreage
West Virginia
Barbour Co. 45 3,993
Doddridge Co. 29 3,451
Harrison Co. 16 1,280
Lewis Co. 23 2,500
Marion Co. 38 4,677
McDowell Co. 2 9,349
Monongalia Co. 20 1,690
Taylor Co. 125 13,381
Preston Co. 1 54
Upshur Co. 6 602
Randolph Co. 2 200
Gilmer Co. 1 759
Pennsylvania
Clearfield Co. 6 3,400
Fayette Co. 9 820
Ohio
Athens Co. 10 700
Washington Co. 8 798
Total 341 47,654
</TABLE>
In addition, PDC expects to acquire additional acreage on an ongoing
basis throughout 1996 and 1997 and beyond for the Program and future
partnerships.
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<PAGE>
Prospect Areas Geology
Northern West Virginia. Northern West Virginia is part of the Plateau
Province of the Appalachian Basin, a region characterized by thick
Paleozoic sediments and gentle northeast trending folds. Upper Devonian
and Mississippian sands have accounted for virtually all gas and oil
production to date in this area. Approximately twenty thousand feet of
sediments underlie the area. The deepest fifteen thousand feet of this
stratigraphic section consist of Cambrian through Middle Devonian aged
rocks which have not produced major amounts of hydrocarbons in the region
excepting the areas where the Oriskany/Huntersville formations are
productive. The Upper Devonian and Mississippian Formations that are the
targets for wells drilled in this area were deposited as part of the
Acadian Clastic Wedge of the Central Appalachian Basin. These rocks were
deposited in a geosynclinal basin located westward of the Acadian Orogenic
Uplift along the eastern margin of the North American Plate. These coarse
grained sediments are part of the Catskill and Price Deltas that prograded
westward across the prospect area.
The deepest target reservoirs are the Elk, Benson and Riley Sandstones
of the Upper Devonian Chemung Formation. These rocks exhibit
characteristics common to offshore marine deposits ranging from distal
submarine fan turbidities to nearshore storm deposits of the shallow shelf
environment. These reservoirs are pure stratigraphic traps, whose gas
accumulations are unrelated to structural features, although higher fluid
saturations are commonly found in the structurally lower areas of the
reservoirs. Commercial production is generally limited to those areas in
which the sand is four feet thick or greater with porosity greater than
8%. These zones are found in narrow belts 1500 to 6000 feet wide.
Thickness ranges from 4 to 12 feet in the inner channel facies of the
reservoir with peak porosity varying from 8% to 18% or more. Permeability
ranges from 0.01 to 2.0 millidarcies. The Balltown and Speechley
Sandstones, located at depths from 2500 to 3500 feet, are interpreted as
shallow shelf deposits and are the transitional sands from the marine
rocks below to the marine/fluvial rocks of the Hampshire Group above.
These reservoirs are typically offshore bars or other related deposits and
are somewhat thicker, cleaner and more coarse grained than the older
deeper water marine rocks. Thickness ranges from 5 to 30 feet or more
with average porosities from 6% to 12% with peak porosities as high as 20%
or more.
The Upper Devonian and Mississippian Sands (Fifth through Keener)
represent the core of the coarse grained sediments of the Catskill and
Price Deltas. The lowermost sands represent the nearshore and shoreline
environment while the upper sands exhibit the geometry of the fluvial
reservoirs of the delta plain environment. During deposition of these
sands sea level fluctuated causing a wide range of sand types to be
deposited throughout the prospect area. Grain size ranges from coarse to
pebbly. Most of the rocks were deposited in a high energy environment and
are very clean and well sorted. Thickness ranges from 5 to 50 feet with
porosity varying from 6% to 25% or more.
Southern West Virginia. Wells drilled in McDowell County will target
three potential gas-bearing reservoirs. The shallowest pays are the upper
and lower Ravencliff Sandstones (upper Hinton Formation), followed by the
upper and lower Maxton Sandstone (lower Hinton Formation) and the Union
member of the Big Lime (Greenbrier Limestone). Any combination of one to
all three of these zones may be commercial in any given well. The most
prolific wells in the immediate prospect area are those wells that
encounter pay quality sand in both the Ravencliff and Maxton.
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<PAGE>
The upper and lower Ravencliff Sandstone pays range from 10 to 80 feet
in gross sand thickness with net porous sand of 5 to 50 feet (feet of sand
with porosity greater than 8%). Geologically the Ravencliff is part of
the upper Hinton Formation of the Mississippian aged Mauch Chunk Group.
In southern West Virginia there is substantial record of marine
sedimentation at the beginning of Mauch Chunk time; however the remainder
of the period was dominated by non-marine clastic sedimentation
deposition. Basal Mauch Chunk units are of mixed carbonate and sandstone
composition and represent shallow nearshore marine deposits. These units
grade upward into deltaic and coastal sandstones, siltstones and shales.
The uppermost Mauch Chunk units are generally red coastal and alluvial
plain sediments. Sand bodies range from lenticular channel fills to sheet
type deposits of near shore marine origin. In Southern West Virginia, the
Ravencliff is typically a series of northeast-southwest trending channel
fill sandstones than can be a singe channel fill or multiple stacked
channel fill sequences (the lower and upper Ravencliff as well as a third
unnamed sand). In the immediate prospect area both the lower and upper
Ravencliff are productive.
The Maxton Sandstone is the drillers' term for the lower Hinton channel
sandstones in the area. These sands are very similar to the Ravencliff in
terms of geologic origin as they are potentially very thick lenticular
channel fill deposits representative of a deltaic progressive sequence.
In the immediate prospect area both the lower and upper Maxton are
productive.
The third potential pay in the prospect area is an oolitic limestone
within the Union Member of the Big Lime (Greenbrier Limestone). These
porous and permeable zones found laterally to dense limestones are
buildups of individual ooliths. Ooliths are formed in high energy calcite
rich waters by precipitation of calcite around a small fragment of shell,
sand or other material. The grains are held in suspension by water energy
and calcite precipitation forms concentric bands around the particle.
Continual growth may generate coarse grain size balls. Banks or bars made
up ooliths form when individual ooliths drop out of suspension around pre-
existing topographic highs or are carried offshore and laid down in
elongate tidal bars adjacent to tidal channels. Tidal currents move back
and forth through the channels allowing for preservation of the adjacent
bars. Across the prospect area and to the northeast, these bars may be
traced through older, established gas fields. The individual oolitic
tidal bars are oriented northwest-southeast, perpendicular to the paleo-
shoreline, average 4500 feet in width, 10 to 40 feet thick and up to 20
miles in length. The non-productive tidal channels separating these bars
average 1.5 miles in width. Oolitic pay zones in the prospect area range
from a few feet in thickness to 20 feet or more with porosity in the 6%
range. Permeability in this reservoir is good but dolomitization of
portions of the reservoir may enhance or destroy original reservoir
character.
West Central Pennsylvania. Wells to be drilled in this area located in
Clearfield County, part of the Plateau Province of the Appalachian Basin.
The geology of this area is very similar to that of northern West Virginia
with Devonian and Mississippian rocks accounting for the majority of the
production. Production in the local prospect area will come from the
Bradford Group (Bradford, Balltown, Tiona, Speechley and Warren
sandstones). These upper Devonian reservoirs are interpreted to be
shallow water marine sandbars and channel fill deposits are similar to
Upper Devonian reservoirs in northern West Virginia.
The primary drilling targets in the area are the First, Second and
Third Bradford sands. Each of these reservoirs contains upper and lower
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<PAGE>
members and production will typically come from 3 or 4 sands in any given
well. In addition to these reservoirs, other mappable primary targets
will include the Balltown, Tiona, Speechley and Warren sandstones.
Secondary targets in portions of the prospect area are the Fifth and
Bayard sandstones. Sand thickness for the primary target reservoirs
ranges from 5 to 25 feet for any individual zone. Cumulative net sand
thickness per well ranges from 40 to 100 feet. Porosity ranges from 5% to
15% with permeability of 0.1 millidarcies or less, classifying these
reservoirs as "tight" sandstones. Typical natural shows from these
reservoirs range from a show to 100 Mcfd and reflect the nature of the
reservoir.
Southeast Ohio. The Clinton and Medina Sandstones are Lower Silurian in
age and were deposited approximately 420 million years ago. The Lower
Silurian section is an excellent example of a transgressive-regressive
deltaic system within the relatively stable craton. Low angle shelf
slopes in crotonic basins produce river dominated delta systems. Wave and
tidal processes are unable to redistribute sediments at the mouths of
distributary channels. These channels frequently change course as older
channels become clogged with sediment, resulting in stacked repetitive
sequences over a wide area.
The Silurian environment of southeast Ohio is marked in the geologic
record by an unconformity on the Ordivician Queenston Shale. Immediately
overlying the Queenston is the Medina Sandstone (Whirlpool Sandstone).
This sand is a fine grained gray to red sandstone. The Medina is
interpreted to be a strand plain or beachline deposit parallel to paleo
shoreline and perpendicular to the direction of sedimentation to the
northeast. The Medina was deposited atop the Queenston unconformity.
Post Medina sea level transgression was responsible for the deposition of
prodelta mudstones of the Cabot Head Shale above the Medina. As sediment
load increased from the east and northeast sea level began retreating to
the south and southwest, delta systems began to creep into the prospect
area from the northeast and east and are responsible for the deposition of
the Lower White Clinton. The White Clinton (Grimsby Sandstone) is a delta
front deposit and is generally a thin bedded, tight sandstone unit that is
cut by thicker blocky channel sequences in some areas. In the prospect
area this unit is generally non-productive. As the delta systems
continued to move west-southwest, delta plain deposits were laid down over
the delta front. The Middle Red Clinton (Cabot Head Sandstone) is evidence
of the aerially exposed sands and shales of this sequence. The Red
Clinton in the prospect area is thought to be bar type deposits although
some case can be made for channel related features as well. Isopach
mapping of the Red Clinton in the prospect area shows a general east-west
trend for overall sand thickness but the more porous reservoir quality
portions of the reservoir appear to be oriented more in a northeasterly
direction. After Red Clinton deposition, a decrease in sediment supply
coupled with an increase in sea level caused the area to again be covered
by shallow seas. Destruction and reworking of delta plain sands and
shales caused the deposition of thin offshore sand bodies of the Stray
Clinton (Thorold Sandstone). In the prospect area these sands are thin,
tight and nonproductive.
The general trend of the Medina in the prospect area is southeast to
northwest. The sand is deposited over a wide area with maximum thickness
reaching 15 feet or more. Individual sand bodies may be several miles
wide and tens of miles in length. Peak porosities may be as high as 16%
but average 6% to 12%. Although the features are large and generally
continuous, there are locally very abrupt changes in reservoir quality.
Successful wells can be drilled by staying within the productive trends as
identified by log analysis and isopach mapping and offsetting productive
wells.
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The Red Clinton in the prospect area is more difficult to develop than
the Medina due to the nature of bar type deposition. The sands are thin
relative to the entire section making net clean sand maps difficult to
construct and interpret. The productive areas can be identified by
developing net porosity thickness maps, evaluating production trends and
from detailed cross section. The nature of deposition of these sand bars
at the top of the Clinton results in discontinuous reservoirs scattered
throughout the prospect area. These productive zones are generally thin,
4 to 15 feet thick, clean, well sorted sandstones with above average
porosity and permeability.
In addition to the areas outlined above, the Managing General Partner
is currently in the initial stages of evaluating potential prospects in
western Pennsylvania and New York. If, in the opinion of the Managing
General Partner, these prospects warrant development, they may be included
in 1996 Partnerships.
Drilling and Completion Phase
- Most Partnership wells are expected to be development wells 3,000 to
5,500 feet deep.
- The Partnership will drill all wells prior to March 30, 1997 for all
Partnerships designated "PDC 1996-_ Limited Partnership" and prior
to March 30, 1998 for all Partnerships designated "PDC 1997-_
Limited Partnership."
- Partnership wells will be drilled near pipelines, gathering systems,
or end users.
- The Partnership will sell production on a competitive basis at the
best available price.
General: It is anticipated that most wells will be drilled to the
3,000 to 5,500 depth to target gas production. Some shallower or deeper
development Prospects may be drilled. Thereafter, the Operator will
complete each well deemed by the Operator to be capable of production of
oil or gas in commercial quantities. Exploratory wells may be drilled to
depths exceeding the proposed developmental well depths indicated above.
In the event the funds allocated for exploratory wells are not used to
drill exploratory wells, such funds together with unexpended completion
funds will be used to drill additional development wells. The Operator
intends to drill all of the Partnerships' wells prior to March 30, 1997
for Partnerships designated "PDC 1996-_ Limited Partnership" and prior to
March 30, 1998 for Partnerships designated "PDC 1997-_ Limited
Partnership."
The Operator, in its sole and absolute discretion, will determine the
depth to which a particular well is drilled based on geologic and other
information available to it. No representations are given herein as to
the depths and formations to be encountered in each Partnership's wells,
except that it is anticipated that most wells will be drilled at least to
a depth of approximately 2,000 feet per gas well. The Managing General
Partner may substitute another operator or operators to perform the duties
of the Operator, on terms and conditions substantially the same as those
discussed herein. The Managing General Partner will supervise the
operations of non-affiliated drilling contractors and subcontractors. In
such case the cost of drilling to the Partnership will be the actual cost
of third-party drilling, plus the Managing General Partner's costs of
supervision, engineering, geology, accounting, and other services
provided, as well as monthly overhead specified in "Compensation to the
Managing General Partner and Affiliates," above.
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<PAGE>
The Managing General Partner will represent each Partnership in all
operations matters, including the drilling, testing, completion and
equipping of wells and the sale of each Partnership's oil and gas
production from wells of which it is the operator. The Managing General
Partner expects to be the operator of all wells in which the Partnerships
own an interest.
The Managing General Partner and its Affiliates will, in some cases,
provide equipment and supplies, and will perform salt water disposal
services and other services for the Partnerships, provided that all such
transactions will be at competitive prices and upon competitive terms.
The Managing General Partner and its Affiliates may sell equipment to the
Partnerships as needed in the drilling or completion of Partnership wells.
All such equipment will be sold at prices competitive in the area of
operations.
Gas Pipeline and Transmission: The Partnership's wells will be drilled
in the vicinity of transmission pipelines, gathering systems, and/or end
users. The Managing General Partner believes that there are sufficient
transmission pipelines, gathering systems, and end users for the
Partnership's production, subject to some seasonal curtailment. The
Partnership will bear the expense of hook-up and/or gathering charges
between the gas wells and the transmission pipelines.
Sale of Production: Each Partnership will sell the oil and gas
produced from its Prospects on a competitive basis at the best available
terms and prices. The Managing General Partner will not make any
commitment of future production that does not primarily benefit the
Partnerships. Generally, purchase contracts for the sale of oil are
cancelable on 30 days' notice, whereas purchase contracts for the sale of
natural gas usually have a term of a number of years and may require the
dedication of the gas from a well for the life of its reserves.
Each Partnership will sell natural gas discovered by it at negotiated
prices based upon a number of factors, such as the quality of the gas,
well pressure, estimated reserves, prevailing supply conditions and any
applicable price regulations promulgated by the Federal Energy Regulatory
Commission. The Partnership expects to sell oil discovered and sold by it
at free market prices. See "Competition, Markets and Regulation."
Drilling and Operating Agreement.
- The Managing General Partner will be operator of and have full
control over the Partnerships' wells.
- The operator must commence drilling wells within 180 days after
funding of the Partnership, but not later than March 30, 1997 for
Partnerships designated "PDC 1996-_ Limited Partnership" and March
30, 1998 for Partnerships designated "PDC 1997-_ Limited
Partnership."
- With respect to completed wells, the Partnerships will pay drilling
fees of $60 per foot for the first 2,200 feet of well depth plus $16
per foot for each additional foot below 2,200 feet to the deepest
penetration of the well; for each well which the Partnerships
determine not to complete, an amount equal to $33 per foot for the
first 2,200 feet of well depth, plus $9 per foot for each additional
foot below 2,200 feet to the deepest penetration of the well.
- The operator will charge the Partnerships $225 per well per month
for production operations on completed wells and $75 per well per
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month for accounting, engineering, management, and general and
administrative expenses.
Upon funding of each Partnership, the particular Partnership will enter
into the Drilling and Operating Agreement (herein, the "Agreement") with
the Managing General Partner as operator (herein, the "Operator"). The
Agreement (filed as Exhibit 10(a) to the Registration Statement) provides
that the Operator will conduct and direct and have full control of all
operations on the Partnership's Prospects. The Operator will have no
liability as operator to the Partnership for losses sustained or
liabilities incurred, except as may result from the Operator's negligence
or misconduct.
The Partnership will pay a proportionate share of lease, development,
and operating costs, and will be entitled to receive a proportionate share
of production subject only to royalties and overriding royalties. Each
Partnership will be responsible only for its obligations and will be
liable only for its proportionate share of the costs of developing and
operating the Prospects; and, in the event of the default of another
party, the Managing General Partner has agreed to indemnify the
Partnership and its Partners for the obligations of such party. If any
party fails or is unable to pay its share of expense within 60 days after
rendition of a statement therefor by the Managing General Partner, the
Managing General Partner will pay the unpaid amount in the proportion that
the interest of each such party bears to the interest of all such parties.
In the event not all participants in a well wish to participate in a
completion attempt, the parties desiring to do so may pay all costs of the
completion attempt including the cost of necessary well equipment and a
gathering pipeline, and such parties will receive all income and pay all
operating costs from the well until they have received an amount equal to
300% of the completion and connection costs, after which time the non-
consenting parties will have the right to receive their original interest
in further revenues and expenses.
The Operator is obligated to commence drilling the wells on each
Prospect within 180 days of the date of the funding of the Partnership,
but in no case later than March 30, 1997 for Partnerships designated "PDC
1996-_ Limited Partnership" and March 30, 1998 for Partnerships designated
"PDC 1997-_ Limited Partnership." The Operator's duties include testing
formations during drilling, and completing the wells by installing such
surface and well equipment, gathering pipelines, heaters, separators,
etc., as are necessary and normal in the area in which the Prospect is
located. The Managing General Partner will pay the drilling and
completion costs of the Operator as incurred, except that the Managing
General Partner is permitted to make advance payments to the Operator
where necessary to secure tax benefits of prepaid drilling costs and there
is a valid business reason. In order to comply with conditions to
securing tax benefits of prepaid drilling costs, the Operator under the
terms of the Agreement will not refund any portion of amounts paid in the
event actual costs are less than amounts paid but will apply any such
amounts solely for payment of additional drilling services to the
Partnership. If the Operator determines that the well is not likely to
produce oil and/or gas in commercial quantities, the Operator will plug
and abandon the well in accordance with applicable regulations.
Each Partnership will bear its proportionate share of the cost of
drilling and completing or drilling and abandoning its wells as follows:
1) The Cost of the Prospect, as defined; and
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2) For intangible well Costs:
(a) For each well completed and placed in production, an amount
equal to the depth of the well in feet at its deepest
penetration as recorded by the drilling contractor multiplied
by $60 per foot for the first 2,200 feet of well depth plus
$16 per foot for each additional foot below 2,200 feet to the
deepest penetration of the well, plus the actual extra
completion cost of zones completed in excess of the cost of
the first zone and actual additional costs for work required
by state law in the event an intermediate or third string of
surface casing is run, plus the actual costs for directional
drilling services, if required; or
(b) For each well which the Partnership elects not to complete, an
amount equal to $33 per foot for the first 2,200 feet of well
depth plus $9 per foot for each additional foot below 2,200
feet to the deepest penetration of the well, as specified
above and actual additional costs for work required by state
law in the event an intermediate or third string of surface
casing is run, plus the actual costs for directional drilling
services, if required; and
3) The tangible Costs of drilling and completing the Partnership wells
and of gathering pipelines necessary to connect the well to the
nearest appropriate sales point or delivery point.
To the extent that a Partnership acquires less than 100% of a Prospect,
its Drilling and Completion Costs of that Prospect will be proportionately
decreased.
In the event the foregoing rates exceed competitive rates available
from other non-affiliated persons in the area engaged in the business of
rendering or providing comparable services or equipment, the foregoing
rates will be adjusted to an amount equal to that competitive rate.
The Agreement provides that the Partnership will pay the Operator the
Prospect Cost and the Dry Hole Cost for each planned well prior to the
Spud date, and the balance of the completed well Costs when the well is
completed and ready for production, in the case of a completed well.
The Operator will provide all necessary labor, vehicles, supervision,
management, accounting, and overhead services for normal production
operations, and will deduct from Partnership revenues a monthly charge of
$225 per well for operations and field supervision and a monthly charge of
$75 per well for accounting, engineering, management, and general and
administrative expenses. Non-routine operations will be billed to the
Partnership at their Cost.
The Partnership will have the right to take in kind and separately
dispose of its share of all oil and gas produced from its Prospects,
excluding its proportionate share of production required for lease
operations and production unavoidably lost. Initially the Partnership
will designate the Operator as its agent to market such production and
authorize the Operator to enter into and bind the Partnership in such
agreements as it deems in the best interest of the Partnership for the
sale of such oil and/or gas. If pipelines which have been built by the
Managing General Partner are used in the delivery of natural gas to
market, the Operator may charge a gathering fee not to exceed that which
would be charged by a non-affiliated third party for a similar service.
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<PAGE>
The production and accounting charges may be adjusted annually
beginning January 1, 1998 with respect to Partnerships designated "PDC
1996-_ Limited Partnership" and January 1, 1999 for Partnerships
designated "PDC 1997-_ Limited Partnership," to an amount equal to the
rates initially established by the Agreement, multiplied by the ratio of
the then current average weekly earnings of Crude Petroleum and Gas
Production workers to the average weekly earnings of Crude Petroleum and
Gas Production workers for 1991, as published by the United States
Department of Labor, Bureau of Labor Statistics, provided that the charge
may not exceed the rate which would be charged by the comparable operators
in the area of operations.
The Agreement will continue in force so long as any such well or wells
produce, or are capable of production, and for an additional period of 180
days from cessation of all production.
Production Phase of Operations
- Gas will be sold to industrial users, gas brokers, interstate
pipelines, or local utilities, subject to market sensitive contracts
whereby the price of gas sold will vary as a result of market forces.
- Contracts for sale of gas will not be completed until after wells
have been drilled.
General. Once the Partnership's wells are "completed" (i.e., all
surface equipment necessary to control the flow of, or to shut down, a
well has been installed, including the gathering pipeline), production
operations will commence.
The Partnership intends to sell gas production from the Partnership's
wells to industrial users, gas brokers, interstate pipelines or local
utilities. The Managing General Partner is currently in negotiations with
various parties to obtain gas purchase contracts. Due to rapidly changing
market conditions and normal contracting procedures, final terms and
contracts will not be completed until after the wells have been drilled.
In recent programs the Managing General Partner has sold most of the gas
from prior programs' wells to Hope Gas, Inc. or to spot market purchasers
on the CNG Transmission system. While this practice has resulted in
favorable pricing and sales results in the short term, this market
concentration also creates certain risks. See "Risk Factors --
Competition, Markets and Regulations," above and "Competition and
Markets," below. As a result of effects of weather on costs, the
Partnership results may be affected by seasonal factors. In addition,
both sales volumes and prices tend to be affected by demand factors with
a significant seasonal component.
Expenditure of Production Revenues. The Partnership's share of
production revenue from a given well will be burdened by and/or subject to
royalties and overriding royalties, monthly operating charges, and other
operating costs.
The above items of expenditure involve amounts payable solely out of,
or expenses incurred solely by reason of, production operations. The
Partnership's only source of revenues will be from production operations,
because the Partnership is not permitted to borrow any funds it may
require to meet operation expenditures (see "Risk Factors -- Shortage of
Working Capital" and "Source of Funds and Use of Proceeds -- Subsequent
Source of Funds"). It is the practice of the Managing General Partner to
deduct operating expenses from the production revenue for the
corresponding period.
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<PAGE>
Interests of Parties
The Managing General Partner, Investor Partners, and unaffiliated
third parties (including landowners) share revenues from production of gas
from wells in which the Partnership has an interest. The following chart
expresses such interest of gross revenues derived from the wells. For the
purpose of this chart, "gross revenues" is defined as the "Well Head Gas
Price" paid by the gas purchaser. In the event the Partnership acquires
less than a 100% Working Interest, the percentages available to the
Partnership will decrease proportionately.
<TABLE>
<S> <S> <S> <S>
Program Revenue Sharing
Partnership
Third Party Working Interest
Entity Interest Royalties: If 12.5% /If 16.125%(1)
_________________________
Managing 20% Partnership
General Interest (2) 17.50% 16.775%
Partner
Investor 80% Partnership
Partners Interest (2) 70.00% 67.100%
Third Landowners and Over-
Parties riding Royalties 12.50% 16.125%
100.0% 100.0%
</TABLE>
____________________
(1) Landowner and other royalty interests payable to unaffiliated third
parties may vary, provided that the weighted average for all
Prospects of a Partnership shall not exceed 16.125%.
(2) The revenues to be distributed are subject to the preferred cash
distribution policy.
Insurance
- The Managing General Partner will carry public liability insurance
of not less than $10 million during drilling operations and will
maintain other insurance as appropriate.
- The Managing General Partner has a good faith duty to provide
insurance coverage, sufficient, in its judgment, to protect the
Investors against the foreseeable risks of drilling.
- Increasing cost of insurance could reduce Partnership funds
available for drilling.
The Managing General Partner, in its capacity as operator, will carry
blowout, loss of well control, pollution, public liability and workmen's
compensation insurance, but such insurance may not be sufficient to cover
all liabilities. Each Unit held by the Additional General Partners
represents an open-ended security for unforeseen events such as blowouts,
lost circulation, stuck drillpipe, etc. which may result in unanticipated
additional liability materially in excess of the per Unit Subscription
amount.
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<PAGE>
The Managing General Partner has obtained various insurance policies,
as described below, and intends to maintain such policies subject to its
analysis of their premium costs, coverage and other factors. The Managing
General Partner may, in its sole discretion, increase or decrease the
policy limits and types of insurance from time to time as it deems
appropriate under the circumstances, which may vary materially. The
following types and amounts of insurance have been obtained and are
expected to be maintained. The Managing General Partner is the
beneficiary under each policy and pays the premiums for each policy,
except the Managing General Partner and the Partnership are co-insured and
co-beneficiaries with respect to the insurance coverage referred to in #2
and #5 below.
1. Workmen's compensation insurance in full compliance with the laws
for the States of West Virginia and Pennsylvania; this insurance
will be obtained for any other jurisdictions where a Partnership
conducts its business;
2. Operator's bodily injury liability and property damage liability
insurance, each with a limit of $1,000,000;
3. Employer's liability insurance with a limit of not less than
$1,000,000;
4. Automobile public liability insurance with a limit of not less than
$1,000,000 per occurrence, covering all automobile equipment; and
5. Operator's umbrella liability insurance with a limit of $19,000,000.
Petroleum Development Corporation ("PDC"), as Managing General Partner
and Operator, has determined in good faith, in the exercise of its
fiduciary duty as Managing General Partner and as Operator, that adequate
insurance has been obtained on behalf of the Partnerships to provide the
Partnership with such coverage as PDC believes is sufficient to protect
the Investor Partners against the foreseeable risks of drilling. The
Managing General Partner will obtain and maintain public liability
insurance, including umbrella liability insurance, of at least two times
the Partnership's capitalization, but in no event less than $10 million
during drilling operations. In the event that PDC participates in
drilling activities other than with respect to those of the Partnership
and as a result of which PDC will have unlimited liability with respect to
those activities, PDC will prior to its participation in such other
drilling activities cause the Partnership to obtain such two-times
insurance coverage whereby the Partnership will be the sole beneficiary
under such insurance. In the event that two Partnerships are conducting
drilling activities simultaneously, as provided for under "Proposed
Activities -- Introduction" above, and the investor capital of such
Partnerships is in excess of $10 million in the aggregate, the Managing
General Partner will obtain additional liability insurance coverage during
drilling in order to provide the above-referenced two-times insurance
coverage (with respect to the total capitalization of those Partnerships
which are conducting simultaneous drilling activities). The Managing
General Partner will maintain such two-times insurance coverage during
such drilling activities. PDC will review the Partnership insurance
coverage prior to commencing drilling operations and periodically evaluate
the sufficiency of insurance. PDC will obtain and maintain such insurance
coverage as it determines to be commensurate with the level of risk
involved. In more than 25 years of operations, drilling more than 1,100
wells in Tennessee, Ohio, Pennsylvania, and West Virginia, PDC's largest
insurance claim has been less than $80,000.
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<PAGE>
Upon completion of drilling of a particular Partnership, the Managing
General Partner will convert all Units of general partnership interest of
that Partnership into Units of limited partnership interest of that
Partnership.
The annual cost of such insurance to the Partnership is estimated to be
approximately $625 per well in the year that it is drilled and
approximately $140 per each producing well for the Partnership liability
and other insurance coverages. The costs of insurance are allocated based
primarily upon the level of natural gas operations. The costs of
insurance have increased significantly in recent years and have currently
stabilized, although insurance premiums may materially increase in the
future. The primary effect of increasing premiums cost is to reduce funds
otherwise available for Partnership drilling operations.
The Managing General Partner will notify all Additional General
Partners at least 30 days prior to any material change in the amount of
such insurance coverage. Within this 30-day period and otherwise after
the expiration of one year following the closing of the offering with
respect to a particular Partnership, Additional General Partners have the
right to convert their Units into Units of limited partnership interest by
giving written notice to the Managing General Partner and will have
limited liability for any Partnership operations conducted after the
conversion date as a Limited Partner effective upon the filing of an
amendment to the Certificate of Limited Partnership of a Partnership.
At any time during this 30-day period, upon receipt of the required
written notice from the Additional General Partner of his intent to
convert, the Managing General Partner will amend the Partnership
Agreement and will file such amendment with the State of West Virginia
prior to the effective date of the change in insurance coverage and thereby
effectuate the conversion of the interest of the former Additional General
Partner to that of a Limited Partner. Effecting conversion is subject to
the express requirement that the conversion will not cause a termination of
the Partnership for federal income tax purposes. However, even after an
election of conversion, an Additional General Partner will continue to
have unlimited liability regarding Partnership activities arising prior
to the effective date of such conversion. See "Terms of the Offering."
The Managing General Partner's Policy Regarding Roll-Up Transactions
Although the Managing General Partner has no intention of engaging the
Partnership in a "roll-up" transaction, it is possible at some
indeterminate time in the future that the Partnership will become so
involved. In general, a roll-up means a transaction involving the
acquisition, merger, conversion, or consolidation of the Partnership with
or into another partnership, corporation or other entity (the "Roll-Up
Entity") and the issuance of securities by the Roll-Up Entity to Investor
Partners in cases where there is also a significant adverse change in the
voting rights of the Partnership, the term of existence of the
Partnership, the compensation of the Managing General Partner, or the
investment objectives of the Partnership. The determination of
"significant adverse change" will be made solely by the Managing General
Partner in the exercise of its reasonable business judgment as manager of
the Partnership and consistent with its obligations as a fiduciary to the
Investor Partners.
The Partnership Agreement provides various policies in the event that
a Roll-Up should occur in the future. These policies include:
(1) An appraisal of all Partnership assets will be obtained from a
competent independent expert, and a summary of the appraisal will
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be included in a report to the Investor Partners in connection
with a proposed Roll-Up;
(2) Any participant who votes "no" on the proposal will be offered a
choice of:
(i) accepting the securities of the Roll-Up Entity offered in the
proposed Roll-Up; or
(ii) either (A) remaining an Investor Partner in the Partnership and
preserving his interests in the Partnership on the same terms
and conditions as existed previously, or (B) receiving cash in
an amount equal to his pro-rata share of the appraised value of
the Partnership's net assets;
(3) The Partnership will not participate in a proposed Roll-Up (i)
which would result in the diminishment of an Investor Partner's
voting rights under the Roll-Up Entity's chartering agreement;
(ii) in which the Investor Partners' right of access to the
records of the Roll-Up Entity would be less than those provided by
the Partnership Agreement; or (iii) in which any of the costs of
the transaction would be borne by the Partnership if the proposed
Roll-Up is not approved by the Investor Partners.
The Partnership Agreement further provides that the Partnership will not
participate in a Roll-Up transaction unless the Roll-Up transaction is
approved by at least 66 2/3% in interest of the Investor Partners. See
Section 5.07(m) of the Partnership Agreement. Congress is currently
considering legislation to address various problems engendered by Roll-
Ups. At the present time, it is impossible to predict what proposals, if
any, will be enacted by Congress.
COMPETITION, MARKETS AND REGULATION
- Competition is intense in all phases of the oil and gas industry,
including the acquisition of Prospects and the sale of production.
- Competition for equipment and services is keen and can adversely
affect drilling costs and the timing of drilling.
- Excess supplies and competition have depressed current gas prices,
and there is no way to predict when more favorable conditions may
return.
- The Partnership expects to sell its gas subject to market sensitive
contracts, whereby the price of gas sold will vary as a result of
market forces.
Competition and Markets
Competition is keen among persons and companies involved in the
exploration for and production of oil and gas. The Partnership will
encounter strong competition at every phase of its business including
acquiring properties suitable for exploration and development and
marketing of oil and gas. It will compete with entities having financial
resources and staffs substantially larger than those available to the
Partnership. There are thousands of oil and gas companies in the United
States, and over 200 in West Virginia. Petroleum Development Corporation
produces approximately 2.5% of the gas produced in West Virginia. The
national supply of natural gas is widely diversified, with no one entity
controlling over 5%. As a result of this competition and Federal Energy
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<PAGE>
Regulatory Commission ("FERC") and Congressional deregulation of the
natural gas industry and gas prices, prices tend to be determined by
competitive forces. Within its area of operations Petroleum Development
Corporation is one of the larger operations. In addition, it operates
gathering systems which make development of some areas more economic for
it than for other competitors. There will also be competition among
operators for drilling equipment, tubular goods, and drilling crews. Such
competition may affect the ability of each Partnership to acquire Leases
suitable for development by the Partnerships and to develop expeditiously
such Leases once they are acquired.
The marketing of any oil and gas produced by the Partnership will be
affected by a number of factors which are beyond the Partnership's control
and whose exact effect cannot be accurately predicted. These factors
include crude oil imports, the availability and cost of adequate pipeline
and other transportation facilities, the marketing of competitive fuels
(such as coal and nuclear energy), and other matters affecting the
availability of a ready market, such as fluctuating supply and demand.
Moreover, in 1992 FERC issued Order No. 636 which requires pipelines to
separate their storage, sales and transportation functions. Order No. 636
established an industry-wide structure for "open-access" transportation
service under which pipelines must provide third parties non-discriminatory
access to transportation service on their systems. The effect of Order No.
636 has been to restructure the natural gas industry and increase its
competitiveness. In recent years, crude oil and natural gas prices declined
due, among several factors, to an oversupply in the world markets. Oil and
gas prices have also been affected, in part, by decreased demand.
Legislation which may be considered by Congress in some respects emphasizes
decreasing demand for, rather than increasing the supply of, oil and gas.
Such legislation could decrease the demand for the Partnerships' production
in the future. (See "Risk Factors -- Competition, Markets and Regulation.")
The free trade agreement between Canada and the United States has eased
restrictions on imports of Canadian gas to the United States. Additionally,
the passage in November 1993 of the North American Free Trade Agreement
("NAFTA") will have some impact on the American gas industry, by eliminating
trade and investment barriers in the United States, Canada, and Mexico. In
addition, a number of new pipeline projects has been proposed to the FERC
which could substantially increase the availability of Canadian gas to certain
U.S. markets. Such imports could have an adverse effect on both the price and
volume of gas sales from Partnership wells.
The accelerating deregulation of natural gas and electricity
transmission has caused, and will continue to cause, a convergence of the
gas and electric industries. Demand for natural gas by the electric power
sector is expected to increase modestly through the next decade.
Increased competition in the electric industry, coupled with the
enforcement of stringent environmental regulations, may lead to an
increased reliance on natural gas by the electric industry.
Members of the Organization of Petroleum Exporting Countries establish
prices and production quotas for petroleum products from time to time with
the intent of reducing the current global oversupply and maintaining or
increasing certain price levels. The Managing General Partner is unable
to predict what, if any, effect such actions will have on the amount of or
the prices received for oil and gas produced and sold from the
Partnerships' wells.
Various parts of the prospect area are crossed by pipelines belonging
to Hope Gas, Equitable Gas, CNG Transmission, and Equitrans. These
companies have all traditionally purchased substantial portions of their
supply from West Virginia or Pennsylvania producers. In addition, all are
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subject to regulations which require them to transport gas for other end
users under certain conditions, mandated by either the West Virginia
Public Service Commission, Pennsylvania Public Utilities Commission, or
the FERC. Transportation on these systems generally requires that gas
delivered meet certain quality standards and that a tariff be paid for
quantities transported.
Adverse market conditions generally have reduced from prior levels the
current revenues and the present value of future revenues from oil and gas
production.
The Partnership expects to sell gas from its wells to Hope Gas,
Equitable Gas, CNG Transmission, as well as local distribution companies
("LDCs"), or on the spot market via open access transportation
arrangements through CNG Transmission, Hope Gas, Eastern American Energy,
or Equitrans. While in the past these purchases were generally made on
the spot market, Order No. 636 has decreased reliance on the spot market
and recent FERC activities have decreased the attractiveness of the spot
market. Under FERC Order No. 636, interstate gas pipelines must separate
their merchant activities from their transportation activities. LDCs are
required to take a much more active role in acquiring their own gas
supplies under Order No. 636. Many are buying gas directly from gas
marketers and are buying their own reserves. At the same time, state
regulatory commissions are reviewing LDC procurement practices more
carefully. These LDCs have attempted to minimize their risks by forgoing
spot purchases and entering into longer-term gas supply contracts, and by
diversifying their supplies.
Moreover, FERC and the industry are encouraging pipelines to develop
electronic bulletin boards ("EBBs") which can provide gas buyers and
sellers real-time data on pipeline capacity and prices across a variety of
pipeline systems. LDCs and marketers are also working to develop
companies, which can access and integrate all of the information available
on all pipelines' EBBs and arrange gas supplies and transportation on
behalf of purchasers from large regions of the country, in order to create
a national market. These systems, and the development of information
service companies, will allow rapid consummation of natural gas
transactions. Gas purchased in West Virginia, could, for example, be used
in Seattle. Although this system may initially lower prices due to
increased competition, it is anticipated to increase natural gas markets
and the reliability of the markets.
The Partnership anticipates that it will sell the gas from its wells
subject to market sensitive contracts, the price of which will increase or
decrease with market forces beyond the control of the Managing General
Partner. In recent years, the Managing General Partner has sold
approximately 70% of the gas produced by its wells to Hope Gas or CNG
Transmission, both subsidiaries of Consolidated Natural Gas. None of
these companies is affiliated with the Managing General Partner. While
these markets have provided above average prices and sales in the past,
this substantial concentration could result in increased risk of shut-in
wells and/or lower prices in the future.
Regulation
- Federal and state laws and regulations have a significant impact on
drilling and production operations.
- Environmental protection regulations may necessitate significant
capital outlays by the Partnership.
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<PAGE>
Production of Partnership oil and gas will also be affected by Federal
and state regulations. In most areas of operations the production of oil
is regulated by conservation laws and regulations, which set allowable
rates of production and otherwise control the conduct of oil operations.
The Partnership's drilling and production operations will also be
subject to environmental protection regulations established by Federal,
state, and local agencies which in turn may necessitate significant
capital outlays which would materially affect the financial position and
business operations of the Partnership (see "Risk Factors -- Environmental
Hazards and Liabilities").
Certain states control production through regulations establishing the
spacing of wells, limiting the number of days in a given month during
which a well can produce and otherwise limiting the rate of allowable
production. Through regulations enacted to protect against waste,
conserve natural resources and prevent pollution, local, state and Federal
environmental controls will also affect Partnership operations. Such
regulations could affect Partnership operations and could necessitate
spending funds on environmental protection measures, rather than on
drilling operations. If any penalties or prohibitions were imposed on a
Partnership for violating such regulations, that Partnership's operations
could be adversely affected.
In prior programs, expenses associated with compliance with
environmental regulations have represented approximately 10-15% of the
cost of drilling and completing wells, and it is expected that similar
costs will be incurred in this program. These costs are included in the
footage-based rates described at "Proposed Activities -- Drilling and
Operating Agreement," above.
Natural Gas Pricing
- The Managing General Partner anticipates that the Partnerships' gas
will be derived primarily from Devonian Shale, that the prices of the
Partnerships' gas will be deregulated, and that the gas will be sold
at fair market value.
Sale of natural gas by the Partnerships will be subject to regulation
of production, transportation and pricing by governmental regulatory
agencies. Generally, the regulatory agency in the state where a producing
gas well is located supervises production activities and, in addition, the
transportation of gas sold into intrastate markets. The FERC regulates
the rates for interstate transportation of natural gas but, pursuant to
the Wellhead Decontrol Act of 1989, FERC may not regulate the price of
gas. Such deregulated gas production may be sold at market prices
determined by supply, demand, Btu content, pressure, location of wells,
and other factors.
The Managing General Partner anticipates that all of the gas produced
by Partnership wells will be considered price decontrolled gas and that
the Partnerships' gas will be sold at fair market value.
Proposed Regulation
Various legislative proposals are being considered in Congress and in
the legislatures of various states, which, if enacted, may significantly
and adversely affect the petroleum and natural gas industries. Such
proposals involve, among other things, the imposition of price controls on
all categories of natural gas production, the imposition of land use
controls (such as prohibiting drilling activities on certain Federal and
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state lands in roadless wilderness areas) and other measures. At the
present time, it is impossible to predict what proposals, if any, will
actually be enacted by Congress or the various state legislatures and what
effect, if any, such proposals will have on the Partnerships' operations.
MANAGEMENT
General Management
The Managing General Partner of the Partnership is Petroleum Development
Corporation ("PDC"), a publicly-owned Nevada corporation organized in
1955. Since 1969, PDC has been engaged in the business of exploring for,
developing and producing oil and gas primarily in the Appalachian Basin
area of West Virginia, Tennessee, Pennsylvania and Ohio. As of September
30, 1995, PDC had approximately 70 employees. PDC will make available to
Investor Partners, upon request, audited financial statements of PDC for
the most recent fiscal year and unaudited financial statements for interim
periods.
The Managing General Partner will actively manage and conduct the
business of the Partnerships, devoting such time and talents to such
management as it shall deem reasonably necessary. The Managing General
Partner will have the full and complete power to do any and all things
necessary and incident to the management and conduct of each Partnership's
business. The Managing General Partner will be responsible for
maintaining Partnership bank accounts, collecting Partnership revenues,
making distributions to the Partners, delivering reports to the Partners,
and supervising the drilling, completion, and operation of the
Partnerships' gas wells.
Experience and Capabilities as Driller/Operator
PDC (the "Company" or the "Managing General Partner") will act as
driller/operator for the Program wells. Since 1969 the Company has
drilled over 1,200 wells in West Virginia, Tennessee, Ohio, and
Pennsylvania. The Company currently operates approximately 800 wells.
The Company employs three geologists who develop Prospects for drilling
by the Company and who help oversee the drilling process. In addition,
the Company has an engineering staff of four who are responsible for well
completions, pipelines, and production operations. The Company employs a
drilling subcontractor, a completion subcontractor, and a variety of other
subcontractors in the performance of the work of drilling contract wells.
In addition to technical management, the Company may provide services, at
competitive rates, from one of four Company-owned service rigs, a water
truck, frac tanks, roustabouts, and other assorted small equipment. The
Company may lay short gathering lines, or may subcontract all or part of
the work where it is more cost effective for a partnership. The Company
employs full-time welltenders and supervisors to operate its wells. In
addition, the engineering staff evaluates reserves of all wells at least
annually and reviews well performance against expectations. All services
provided by the Managing General Partner are provided at rates less than
or equal to prevailing rates for similar services provided by unaffiliated
persons in the area.
Petroleum Development Corporation
The executive officers, directors and key technical personnel of PDC,
their principal occupations for the past five years and additional
information are set forth below:
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<PAGE>
<TABLE>
<S> <S> <S> <S>
Positions and Held Current
Name Age Offices Held Position Since
James N. Ryan 64 Chairman, Chief November 1983
Executive Officer
and Director
Steven R. Williams 44 President and March 1983
Director
Roger J. Morgan 68 Secretary and November 1969
Director
Dale G. Rettinger 51 Executive Vice July 1980
President, Treasurer
and Director
Vincent F. D'Annunzio 42 Director February 1989
Jeffrey C. Swoveland 40 Director March 1991
Ersel Morgan 52 Vice President April 1995
Production
Eric Stearns 37 Vice President April 1995
Exploration and
Development
Alan Smith 37 Senior Geologist April 1980
Jeff Stevens 38 Senior Engineer May 1981
Bob Williamson 41 Geologist February 1991
</TABLE>
James N. Ryan has served as President and Director of PDC from 1969 to
1983 and was elected Chairman and Chief Executive Officer in March 1983.
Steven R. Williams has served as President and Director of PDC since
March 1983. Prior to joining the Company, Mr. Williams was employed by
Exxon until 1979 and attended Stanford Graduate School of Business,
graduating in 1981. He then worked with Texas Oil and Gas until July
1982, when he joined Exco Enterprises, an oil and gas investment company,
as manager of operations.
Roger J. Morgan has been a member of the law firm of Young, Morgan &
Cann, Clarksburg, West Virginia, for more than the past five years. Mr.
Morgan is not active in the day-to-day business of PDC, but his law firm
provides legal services to PDC.
Dale G. Rettinger has served as Vice President and Treasurer of PDC
since July 1980. Mr. Rettinger was elected Director in 1985. Previously,
Mr. Rettinger was a partner with Main Hurdman, Certified Public
Accountants, having served in that capacity since 1976.
Vincent F. D'Annunzio has for the past five years served as president
of Beverage Distributors, Inc., located in Clarksburg, West Virginia. Mr.
D'Annunzio is a director of West Union Bank, West Union, West Virginia.
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<PAGE>
Jeffrey C. Swoveland has been Director of Finance with Equitable
Resources, Inc. since September 1994. Prior thereto, he was a lending
officer with Mellon Bank N.A. since July 1989. Mr. Swoveland was Senior
Planning Analyst with Consolidated Natural Gas in 1988 and 1989. Mr.
Swoveland received an MS degree in finance from Carnegie Mellon
University.
Ersel Morgan was elected Vice President-Production in April 1995. He
joined PDC as a landman in 1980.
Eric Stearns was elected Vice President-Exploration and Development in
April 1995. Mr. Stearns joined PDC in 1985 after working as a mudlogger
for Hywell, Incorporated logging wells in the Appalachian Basin between
1982 and 1985, and for Petroleum Consultants, Inc. between 1984 and 1985.
Since joining PDC, Mr. Stearns has also worked on the development and
drilling of Benson prospects. Mr. Stearns has a BS degree in geology from
Virginia Tech.
Alan Smith joined PDC in April 1980 as a geologist in the Tennessee
Division. He has a BS degree in geology from Tennessee Technological
University. As a senior geologist he has been responsible for the
development of Benson prospects and drilling operations since 1983.
Jeff Stevens joined PDC full time in May of 1981 after receiving his BS
degree in petroleum engineering and mining from West Virginia University.
Prior to that, he had worked part time for PDC as student engineer. Mr.
Stevens' responsibilities include designing and managing pipe strings,
cement and completions, as well as with production operations.
Bob Williamson joined PDC on February 1, 1991, as a geologist. Mr.
Williamson received a B.S. degree in geology from West Virginia University
in 1980. Prior to joining PDC, he worked as a geologist for Ramco in
Belpre, Ohio, for nearly nine years on projects in West Virginia,
Kentucky, Kansas, and Oklahoma.
Certain Shareholders of Petroleum Development Corporation
The following table sets forth information as of June 30, 1995, with
respect to the common stock of PDC owned by each person who owns
beneficially 5% or more of the outstanding voting common stock, by all
directors individually, and by all directors and officers as a group.
<TABLE>
<S> <S> <S>
Amount Percent
Name Beneficially of Class
Owned(1)
PNC Bank, N.A. 1,200,000(2) 10.9
James N. Ryan 1,012,382(3) 8.9
Fidelity Management 932,500 8.4
Steven R. Williams 571,794(4) 5.0
Dale G. Rettinger 525,834(4) 4.8
Roger J. Morgan 217,554(5) 1.9
Vincent D'Annunzio 140,250(6) 1.3
Jeffrey C. Swoveland 30,250(7) 0.3
All Directors and Officer
as a Group (7 persons) 2,747,741(8) 21.8
</TABLE>
____________________
(1) The nature of the beneficial ownership for all the shares is sole
voting and investment power.
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<PAGE>
(2) Petroleum Development Corporation has an option to reacquire
1,200,000 shares at prices approximating market. The option expires
on April 30, 1997.
(3) Includes options to purchase 331,000 shares exercisable within 60
days.
(4) Includes options to purchase 321,000 shares exercisable within 60
days.
(5) Includes options to purchase 187,500 shares exercisable within 60
days.
(6) Includes options to purchase 130,250 shares exercisable within 60
days.
(7) Includes options to purchase 30,250 shares exercisable within 60
days.
(8) Includes options to purchase 1,556,000 shares exercisable within 60
days. Until exercised, these options cannot be voted. All
directors and officers as a group own in the aggregate a total of
1,191,741 shares or approximately 10.8% of the total of 11,040,627
shares of common stock issued and outstanding.
Remuneration
No officer or director of the Managing General Partner will receive any
direct remuneration or other compensation from the Partnerships. Such
persons will receive compensation solely from PDC. Information as to
compensation paid by the Managing General Partner to its directors and
executive officers may be obtained from publicly available reports filed
by the Managing General Partner with the Securities and Exchange
Commission pursuant to the Securities Exchange Act of 1934.
Legal Proceedings
The Managing General Partner as driller/operator is subject to certain
minor legal proceedings arising from the normal course of business. Such
legal actions are not considered material to the operations of the
Managing General Partner or the Partnership.
CONFLICTS OF INTEREST
- The Managing General Partner currently manages and in the future
will sponsor and manage natural gas drilling programs similar to the
Partnerships.
- The Managing General Partner decides which Prospects each
Partnership will acquire.
- The Managing General Partner will act as operator of the
Partnerships; the terms of the drilling and operating agreement have
not been negotiated by non-affiliated persons.
- The Managing General Partner will furnish drilling and completion
services with respect to Partnership wells.
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<PAGE>
- The Managing General Partner is general partner of numerous other
partnerships, and owes duties of good-faith dealing to such other
partnerships.
- The Managing General Partner and affiliates engage in significant
drilling, operating, and producing activities for other
partnerships.
The Partnerships are subject to various conflicts of interest arising
out of their relationship with the Managing General Partner. These
conflicts include, but are not limited to, the following:
Future Programs by Managing General Partner and Affiliates. The
Managing General Partner has the right, and expects to continue, to
organize and manage oil and gas drilling programs in the future similar to
the subject Partnerships, and to conduct operations now and in the future,
jointly or separately, on its own behalf or for other private or public
investors. Affiliates of the Managing General Partner also intend to
conduct such activities on their own behalf. Officers, directors and
employees of the Managing General Partner have participated, and will
participate in the future, at cost, in Working Interests in wells in which
the Managing General Partner and its partnerships participate. To the
extent Affiliates of the Managing General Partner invest in the
Partnerships or other partnerships sponsored by the Managing General
Partner, conflicts of interest will arise.
Fiduciary Responsibility of the Managing General Partner. The Managing
General Partner is accountable to the Partnership as a fiduciary and
consequently has a duty to exercise good faith and to deal fairly with the
investors in handling the affairs of the Partnership. While the Managing
General Partner will endeavor to avoid conflicts of interest to the extent
possible, such conflicts nevertheless may occur and, in such event, the
actions of the Managing General Partner may not be most advantageous to
the Partnership and could fall short of the full exercise of such
fiduciary duty. In the event the Managing General Partner should breach
its fiduciary responsibilities, an Investor Partner would be entitled to
an accounting and to recover any economic losses caused by such breach.
Independent Representation in Indemnification Proceeding. Counsel to
the Partnership and to the Managing General Partner in connection with
this offering are the same. Such dual representation will continue in the
future. However, in the event of an indemnification proceeding between
the Managing General Partner and the Partnership, the Managing General
Partner will cause the Partnership to retain separate and independent
counsel to represent its interest in such proceeding.
Due Diligence Review. PDC Securities Incorporated, the Dealer Manager
of the offering, is an Affiliate of the Managing General Partner and its
due diligence examination concerning this offering cannot be considered to
be independent. See "Plan of Distribution."
Managing General Partner's Interest. Although the Managing General
Partner believes that its interest in Partnership profits, losses, and
cash distributions is equitable (see "Participation in Costs and
Revenues"), such interest was not determined by arm's-length negotiation.
Transactions between the Partnership and Operator. The Managing General
Partner will also act as Operator. Accordingly, although the Managing
General Partner believes the terms of the Drilling and Operating Agreement
will be equitable, it will not be the subject of arm's-length
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<PAGE>
negotiation. Furthermore, the Managing General Partner may be confronted
with a continuing conflict of interest with respect to the exercise and
enforcement of the rights of the Partnership under such Operating
Agreement. See "Transactions with the Managing General Partner or
Affiliates Thereof," below.
Conflicting Drilling Activities. Affiliates of the Managing General
Partner have engaged in significant drilling and producing activities for
the accounts of affiliated partnerships related to previous drilling
programs. In addition, the Managing General Partner and its Affiliates
manage and operate gas properties for investors in such other drilling
programs. Although the Partnership Agreement attempts to minimize any
potential conflicts, the Managing General Partner will be in a position to
decide whether a gas property will be retained or acquired for the account
of the Partnership or other drilling programs which the Managing General
Partner or its Affiliates may presently operate or operate in the future.
Conflicts with Other Programs. The Managing General Partner realizes
that its conduct and the conduct of its Affiliates in connection with the
other drilling programs could give rise to a conflict of interest between
the position of PDC as Managing General Partner of the Partnership and the
position of PDC or one of its Affiliates as general partner or sponsor of
such additional programs. In resolving any such conflicts, each
Partnership will be treated equitably with such other partnerships on a
basis consistent with the funds available to the partnerships and the time
limitations on the investment of funds. However, no provision has been
made for an independent review of conflicts of interest. The Managing
General Partner believes that the possibility of conflicts of interest
between the Partnership and prior programs is minimized by the fact that
substantially all the funds available to prior drilling programs in which
the Managing General Partner or an Affiliate serves as general partner
have been committed to a specific drilling program.
The Managing General Partner follows a policy of developing next what
it judges to be the best available Prospect. Acquisition of new Leases
and information derived from wells already drilled result in a constant
change in this assessment. Only one investor-financed partnership may
participate in each well, except for the first and final partnership well
if funds with respect to the last well do not exist for the purchase of a
majority working interest. The Managing General Partner anticipates that
generally only one Partnership will be actively engaged in drilling at any
time. However, in the event more than one Partnership has funds available
for drilling, the Partnerships will alternate drilling of wells based on
the "best available prospect" format. The determination of the "best
available Prospect" is based on the Managing General Partner's assessment
of the economic potential of a Prospect and its suitability to a
particular partnership, and considers various factors including estimated
reserves, target geological formations, gas markets, geological and gas
market diversification within the partnership, royalties and overrides on
the Prospect, estimated lease and well costs, and limitations imposed by
the prospectus and/or partnership agreements.
The Partnership Agreement authorizes the Managing General Partner to
cause the Partnership to acquire undivided interests in natural gas
properties, and to participate with other parties, including other
drilling programs heretofore or hereafter conducted by the Managing
General Partner or its Affiliates, in the conduct of exploration and
drilling operations thereon. Because the Managing General Partner must
deal fairly with the investors in all of its drilling programs, if
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<PAGE>
conflicts between the interest of the Partnership and such other drilling
programs do arise, they may not in every instance be resolved to the
maximum advantage of the Partnership.
From time to time, the Managing General Partner may cause Partnership
Prospects to be enlarged or contracted on the basis of geological data to
define the productive limits of any pool discovered. The Partnership is
not required to expend additional funds for the acquisition of property
unless such acquisition can be made from the Capital Contributions. In
the event such property is not acquired by the Partnership, the
Partnership may lose a promising Prospect. Except as otherwise provided
by the Partnership Agreement, such Prospect might be acquired by the
Managing General Partner or an Affiliate thereof or other drilling
programs conducted by them.
In addition, subject to the restrictions set forth below, the Managing
General Partner in its sole discretion decides which Prospects and what
interest therein to transfer to the Partnership. This may result in
another drilling program sponsored by the Managing General Partner
acquiring property adjacent to Partnership property. Such other program
could gain an advantage over the Partnership by reason of the knowledge
gained through the Partnership's prior experience in the area or if such
other drilling program were the first to discover or develop a productive
pool of oil or natural gas.
Acquisition of Prospects. The Managing General Partner has discretion
in selecting leases to be acquired by the Partnership from the Managing
General Partner or its Affiliates or third parties and the location and
type of operations which the Partnership will conduct on such leases.
Certain of such leases may be part of the Managing General Partner's
existing inventory, although no leases have been designated for inclusion
in the Partnership at the present time. Neither the Managing General
Partner nor any Affiliate will retain undeveloped acreage adjoining a
Partnership Prospect in order to use Partnership funds to "prove up" the
acreage owned for its own account.
Whenever the Managing General Partner sells, transfers or conveys an
interest in a Prospect to a particular Partnership, it must, at the same
time, sell to the Partnership an equal proportionate interest in all of
its Leases in the same Prospect (except any interests in producing wells).
If the Managing General Partner or an Affiliate (except another affiliated
limited partnership in which the interest of the Managing General Partner
or its Affiliates is identical or less than their interest in the
Partnerships) subsequently proposes to acquire an interest in a Prospect
in which a Partnership possesses an interest or in a Prospect abandoned by
the Partnership within one year preceding such Prospect acquisition, the
Managing General Partner or such Affiliate will offer an equivalent
interest therein to the Partnership; and, if cash or financing is not
available to such Partnership to enable it to consummate a purchase of an
equivalent interest in such property, neither the Managing General Partner
nor any of its Affiliates will acquire such interest or property, but the
term "Affiliate" will not include another partnership where the Managing
General Partner's or its Affiliates' interest is identical to, or less
than, their interest in the subject Partnerships. The term "abandon"
means the termination, either voluntarily or by operation of the Lease or
otherwise, of all of a Partnership's interest in the Prospect. These
limitations will not apply after the lapse of five years from the date of
formation of a Partnership.
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<PAGE>
A sale, transfer or conveyance to the Partnership of less than all of
the Managing General Partner's or its Affiliates' interest in any Prospect
is prohibited unless the interest retained by the Managing General Partner
or its Affiliates is a proportionate Working Interest, the respective
obligations of the Partnership and the Managing General Partner or its
Affiliates are substantially the same immediately after the sale of the
interest, and the Managing General Partner's or its Affiliates' interest
in revenues does not exceed an amount proportionate to the retained
Working Interest. Neither the Managing General Partner nor its Affiliates
will retain any Overriding Royalty Interests or other burdens on the Lease
interests conveyed to the Partnerships, and will not enter into any
Farmout arrangements with respect to its retained interest, except to
nonaffiliated third parties.
The Partnerships will acquire only those Leases reasonably expected to
meet the stated purposes of the Partnerships. The Partnerships will not
acquire any Lease for the purpose of a subsequent sale or farmout unless
the acquisition is made after a well has been drilled to a depth
sufficient to indicate that such an acquisition would be in the
Partnerships' best interest. The Managing General Partner expects that
the Partnership will develop substantially all of its Leases and will farm
out few, if any, Leases. The Partnerships will not farm out, sell or
otherwise dispose of Leases unless the Managing General Partner,
exercising the standard of a prudent operator, determines that: (a) a
Partnership lacks sufficient funds to drill on the Lease and cannot obtain
suitable alternative financing; (b) downgrading subsequent to a
Partnership's acquisition has rendered drilling undesirable; (c) drilling
would concentrate excessive funds in one location creating undue risk to
a Partnership; or (d) the best interests of a Partnership, based on the
standard of a prudent operator, would be served by such disposition. In
the event of a Farmout, the Managing General Partner will retain for the
Partnerships such economic interests and concessions as a reasonably
prudent operator would retain under the circumstances. The Managing
General Partner will not farm out a Lease for the primary purpose of
avoiding payments of its Partnership share of costs of drilling thereon.
However, the decision with respect to making Farmouts and the terms
thereof involve conflicts of interest because the Managing General Partner
may benefit from cost savings and reduction of risk, and in the event of
a Farmout to an affiliated limited partnership or other Affiliate, the
Managing General Partner or its Affiliates will represent both related
entities.
Transactions with the Managing General Partner or Affiliates Thereof.
The Managing General Partner will furnish drilling and completion services
with respect to all of the Partnership wells. In addition, the Managing
General Partner will act as operator for the producing wells of the
Partnership. The prices to be charged the Partnership for such supplies
and services will be competitive with the prices of other unaffiliated
persons in the same geographic area engaged in similar businesses. The
Managing General Partner expects to earn a profit for such services.
Neither the Managing General Partner nor any Affiliate thereof will
render to the Partnership any gas field, equipage or other services nor
sell or lease to the Partnership any equipment or related supplies unless
such person is engaged, independently of the Partnership and as an
ordinary and ongoing business, in the business of rendering such services
or selling or leasing such equipment and supplies to a substantial extent
to other persons in the gas industry in addition to partnerships in which
the Managing General Partner or its Affiliate has an interest, or, if
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such person is not engaged in such a business then such compensation,
price or rental will be the cost of such services, equipment or supplies
to such person or the competitive rate which could be obtained in the
area, whichever is less. Notwithstanding any provision to the contrary,
the Managing General Partner and its Affiliates may not profit by drilling
in contravention of their fiduciary obligations to the Investor Partners.
Any services not otherwise described in this Prospectus for which the
Managing General Partner or any of its Affiliates are to be compensated
will be embodied in a written contract which precisely describes the
services to be rendered and the compensation to be paid.
All benefits from marketing arrangements or other relationships
affecting the property of the Managing General Partner or its Affiliates
and the Partnerships will be fairly and equitably apportioned according to
the respective interests of each.
Partnership funds will not be commingled with those of any other
entity.
No loans may be made by the Partnership to the Managing General Partner
or any Affiliate thereof.
The Managing General Partner or any Affiliate, other than other
programs sponsored by the Managing General Partner or its Affiliates, may
not purchase the Partnerships' producing properties.
Conflict in Establishing Unit Repurchase Price. Under the Managing
General Partner's Unit Repurchase Program (See "Terms of the Offering --
Unit Repurchase Program" above), the Managing General Partner, once it has
received a request from an Investor Partner that the Managing General
Partner repurchase that Partner's Units, will establish an offering price.
An offering price established by the Managing General Partner will be
arbitrarily determined by the Managing General Partner and will not
necessarily represent the fair market value of the Units. The Managing
General Partner in setting the price will consider its available funds and
its desire to acquire production as represented by the Units. A conflict
will arise in that the price to be set will be that which the Managing
General Partner considers to be in its own best interest (and thereby keep
the repurchase price as low as possible) and not necessarily in the best
interest of the Investor Partner who is presenting the Units for
repurchase.
Certain Transactions
As of November 30, 1995, previous limited partnerships sponsored by
the Managing General Partner and its Affiliates had made payments to the
Managing General Partner or its Affiliates as follows:
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<TABLE>
<S> <S> <S> <S> <S> <S> <S>
Footage
and
Daywork
Drilling General
Contracts, and
Non- Turnkey Services, Admini-
recurring Drilling Chemicals, strative
Name Manage- and Supplies Opera- Expense
of ment Sales Completion and tor's Reimburse-
Partnership Fee of Leases Contracts Equipment Charges ment
Pennwest
Petroleum
Group 1984 $61,556 $46,250 $ -- $1,824,938 $187,119 $ --
Pennwest
Petroleum
Group
1985-A 58,125 43,400 -- 1,829,937 187,334 --
Petrowest
Gas Group
1986-A 29,605 22,400 -- 873,847 89,624 --
Petrowest
Gas Group
1987 35,395 24,850 -- 1,062,332 108,718 --
Petrowest
Gas Group
1987-B 30,461 21,350 -- 913,794 93,514 --
PDC 1987 14,079 8,715 459,153 -- -- --
PDC 1988 23,842 17,150 -- 708,200 72,534 --
PDC 1988-B 26,053 16,450 -- 779,587 79,604 --
PDC 1988-C 41,052 26,250 1,361,857 -- -- --
PDC 1989-P 47,171 34,230 -- 1,445,275 143,875 --
PDC 1989-A 30,250 57,137 -- 1,085,641 -- --
PDC 1989-B 92,750 175,194 3,328,695 -- -- --
PDC 1990-A 35,150 62,209 -- 1,265,680 -- --
PDC 1990-B 55,525 72,100 -- 2,025,511 -- --
PDC 1990-C 86,950 117,215 -- 3,167,563 -- --
PDC 1990-D 92,138 137,225 3,343,524 -- -- --
PDC 1991-A 68,475 75,193 -- 2,511,640 -- --
PDC 1991-B 46,587 62,209 -- 1,697,764 -- --
- 79 -
<PAGE>
PDC 1991-C 68,400 70,235 -- 2,513,765 -- --
PDC 1991-D 131,463 153,721 4,812,667 -- -- --
PDC 1992-A 72,717 77,319 -- 2,669,888 -- --
PDC 1992-B 74,478 58,829 -- 2,754,778 -- --
PDC 1992-C 159,722 149,657 -- 5,884,302 -- --
PDC 1993-A -- 101,335 2,840,609 -- -- --
PDC 1993-B -- 80,470 -- 2,286,886 -- --
PDC 1993-C -- 96,248 -- 2,849,439 -- --
PDC 1993-D -- 94,098 -- 2,724,096 -- --
PDC 1993-E -- 272,730 6,930,264 -- -- --
PDC 1994-A 51,387 110,084 -- 2,248,204 -- --
PDC 1994-B 67,245 85,240 -- 2,921,974 -- --
PDC 1994-C 58,647 63,548 -- 2,545,795 -- --
PDC 1994-D 188,719 232,410 8,024,046 -- -- --
PDC 1995-A(1) 36,640 36,389 -- 1,566,615 -- --
PDC 1995-B(2) 46,441 59,044 -- 1,972,759 -- --
PDC 1995-C(3) 52,862 -- -- 2,312,730 -- --
</TABLE>
____________________
(1) Partnership funded in May 1995.
(2) Partnership funded in September 1995.
(3) Partnership funded in November 1995.
FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER
- The Managing General Partner is accountable to the Partnerships as
a fiduciary and must exercise good faith respecting the
Partnerships.
- The Partnership Agreement includes provisions indemnifying the
Managing General Partner against liability for losses suffered by
the Partnership resulting from actions by the Managing General
Partner.
The Managing General Partner is accountable to the Partnerships as a
fiduciary and consequently must exercise utmost good faith and integrity
in handling Partnership affairs. Under West Virginia law, the Managing
General Partner will owe the Investor Partners a duty of utmost good
faith, fairness, and loyalty. In this regard, the Managing General
Partner is required to supervise and direct the activities of the
Partnership prudently and with that degree of care, including acting on an
- 80 -
<PAGE>
informed basis, which an ordinarily prudent person in a like position
would use under similar circumstances. Moreover, the Managing General
Partner must act at all times in the best interests of the Partnership and
the Investor Partners. Since the law in this area is rapidly developing
and changing, investors who have questions concerning the responsibilities
of the Managing General Partner should consult their own counsel. Where
the question has arisen, courts have held that a limited partner may
institute legal action on behalf of himself and all other similarly
situated limited partners (a class action) to recover damages for a breach
by a general partner of his fiduciary duty, or on behalf of the
partnership (a partnership derivative action) to recover damages from
third parties. In addition, limited partners may have the right, subject
to procedural and jurisdictional requirements, to bring partnership class
actions in Federal courts to enforce their rights under the Federal
securities laws. Further, limited partners who have suffered losses in
connection with the purchase or sale of their interests in a partnership
may be able to recover such losses from a general partner where the losses
result from a violation by the general partner of the antifraud provisions
of the Federal securities laws. The burden of proving such a breach, and
all or a portion of the expense of such lawsuit, would have to be borne by
the limited partner bringing such action. In the event of a lawsuit for
a breach of its fiduciary duty to the Partnership and/or the Investor
Partners, the Managing General Partner, depending upon the particular
circumstances involved, might be able to avail itself under West Virginia
law of various defenses to the lawsuit, including statute of limitations,
estoppel, laches, and doctrines such as the "clean hands" doctrine.
The Partnership Agreement provides for indemnification of the Managing
General Partner against liability for losses arising from the action or
inaction of the Managing General Partner, if the Managing General Partner,
in good faith, determined that such course of conduct was in the best
interests of the Partnership and such course of conduct did not constitute
negligence or misconduct of the Managing General Partner. The Managing
General Partner may not be indemnified for any such liability arising out
of a breach of its duty to the Partnership or the negligence, fraud, bad
faith or misconduct of the Managing General Partner in the performance of
its fiduciary duty. The Partnership Agreement provides for
indemnification of the Managing General Partner by the Partnership for any
losses, judgments, liabilities, expenses and amounts paid in settlement of
any claims sustained by it in connection with the Partnership, provided
that the same were not the result of negligence or misconduct on the part
of the Managing General Partner. Nevertheless, the Managing General
Partner shall not be indemnified for liabilities arising under Federal and
state securities laws unless (1) there has been a successful adjudication
on the merits of each count involving securities law violations or (2)
such claims have been dismissed with prejudice on the merits by a court of
competent jurisdiction or (3) a court of competent jurisdiction approves
a settlement of such claims against a particular indemnitee and finds that
indemnification of the settlement and the related costs should be made,
and the court considering the request for indemnification has been advised
of the position of the Securities and Exchange Commission and of the
position of any state securities regulatory authority in which securities
of the Partnership were offered or sold as to indemnification for
violations of securities laws; provided, however, the court need only be
advised of the positions of the securities regulatory authorities of those
states (i) which are specifically set forth in the Prospectus and (ii) in
which plaintiffs claim they were offered or sold Partnership Units. A
successful claim for indemnification would deplete Partnership assets by
the amount paid. As a result of such indemnification provisions, a
purchaser of Units may have a more limited right of legal action than he
would have if such provision were not included in the Partnership
- 81 -
<PAGE>
Agreement. To the extent that the indemnification provisions purport to
include indemnification for liabilities arising under the Securities Act
of 1933 (the "Securities Act"), in the opinion of the Securities and
Exchange Commission, such indemnification is against public policy as
expressed in the Securities Act, and is, therefore, unenforceable.
The Partnership Agreement also provides that the Partnership shall not
incur the cost of the portion of any insurance which insures any party
against any liability as to which such party is prohibited from being
indemnified.
PRIOR ACTIVITIES
Prior Partnerships
Petroleum Development Corporation ("PDC"), as general partner, has
previously sponsored ten private and six public drilling programs which
have raised a total of $93,956,887. PDC 1996-1997 Drilling Program (the
"Program") is the seventh public drilling program sponsored by PDC as
general partner.
Each of the prior programs has had as its objective the drilling,
completion, and production of oil and natural gas from development wells.
The 1984 and 1985 partnerships split investment between shallow oil wells
located in Pennsylvania, and gas wells located in the area of operations
in which the Program's wells will be located. All of the partnerships
since and including 1986 were targeted at shallow development gas wells
located within the area in which the Program's wells will be drilled. All
funds raised for previous partnerships were spent according to plans as
described in the respective private placement memorandum or prospectus.
All of the partnerships continue in operation, with monthly cash
distributions to investors in all programs continuing. All of the
previous programs realized the anticipated tax benefits, and to date the
IRS has neither audited any partnership nor challenged any deductions or
credits claimed by investors, to the best of the Managing General
Partner's knowledge.
FOR SEVERAL REASONS, INCLUDING THE UNPREDICTABILITY OF NATURAL GAS
DEVELOPMENT AND PRICING AND DIFFERENCES IN PROPERTY LOCATIONS, PROGRAM
SIZE, AND ECONOMIC CONDITIONS, OPERATING RESULTS OBTAINED BY THESE PRIOR
PARTNERSHIPS SHOULD NOT BE CONSIDERED AS INDICATIVE OF THE OPERATING
RESULTS OBTAINABLE BY THE PARTNERSHIPS. IT SHOULD NOT BE ASSUMED THAT
INVESTOR PARTNERS IN THE OFFERING COVERED BY THIS PROSPECTUS WILL
EXPERIENCE RETURNS, IF ANY, COMPARABLE TO THOSE EXPERIENCED BY INVESTORS
IN PRIOR PROGRAMS.
The following table is presented to indicate certain sale
characteristics concerning previous gas limited partnerships sponsored by
the Managing General Partner and its Affiliates.
- 82 -
<PAGE>
<TABLE>
<S> <S> <S> <S> <S> <S> <S>
Number
Date of Date of of Subscrip- Previous
Partnership First Revenue Units Price tions from Assess-
Partnership Formation Distribution Sold Per Unit Participants ment
(1)
Pennwest
Petroleum
Group 1984 12/84 4/85 32.83 $75,000 $2,462,500 --
Pennwest
Petroleum
Group 1985-A 11/85 3/86 31 75,000 2,325,000 --
Petrowest
Gas Group
1986-A 11/86 4/87 15 75,000 1,125,000 --
Petrowest
Gas Group
1987 8/87 1/88 67.25 20,000 1,345,000 --
Petrowest
Gas Group
1987-B 11/87 4/88 57.875 20,000 1,157,500 --
PDC 1987 12/87 6/88 26.75 20,000 535,000 --
PDC 1988 7/88 12/88 45.3 20,000 906,000 --
PDC 1988-B 11/88 4/89 49.5 20,000 990,000 --
PDC 1988-C 12/88 6/89 78 20,000 1,560,000 --
PDC 1989-P 6/89 12/89 89.625 20,000 1,792,500 --
PDC 1989-A 10/89 4/90 60.5 20,000 1,210,000 --
PDC 1989-B 12/89 6/90 185.5 20,000 3,710,000 --
PDC 1990-A 6/90 11/90 70.3 20,000 1,406,000 --
PDC 1990-B 9/90 1/91 111.05 20,000 2,221,000 --
PDC 1990-C 11/90 5/91 173.9 20,000 3,478,000 --
PDC 1990-D 12/90 6/91 184.275 20,000 3,685,500 --
PDC 1991-A 3/91 11/91 136.95 20,000 2,739,000 --
PDC 1991-B 9/91 2/92 93.175 20,000 1,863,500 --
PDC 1991-C 11/91 4/92 136.80 20,000 2,736,000 --
PDC 1991-D 12/91 6/92 262.925 20,000 5,258,500 --
PDC 1992-A 5/92 11/92 145.435 20,000 2,908,700 --
PDC 1992-B 9/92 1/93 148.955 20,000 2,979,100 --
- 83 -
<PAGE>
PDC 1992-C 11/92 4/93 319.444 20,000 6,388,900 --
PDC 1993-A 12/92 6/93 151.30 20,000 3,026,000 --
PDC 1993-B 5/93 11/93 121.75 20,000 2,435,000 --
PDC 1993-C 9/93 2/94 152.34 20,000 3,046,700 --
PDC 1993-D 11/93 4/94 145.45 20,000 2,909,000 --
PDC 1993-E 12/93 7/94 367.94 20,000 7,358,800 --
PDC 1994-A 5/94 11/94 102.775 20,000 2,055,500 --
PDC 1994-B 9/94 2/95 134.49 20,000 2,689,804 --
PDC 1994-C 11/94 4/95 117.294 20,000 2,345,870 --
PDC 1994-D 12/94 6/95 377.438 20,000 7,548,761 --
PDC 1995-A 5/95 10/95(2) 73.28 20,000 1,465,603 --
PDC 1995-B 9/95 1/96(3) 92.88 20,000 1,857,648 --
PDC 1995-C 11/95 (4) 105.72 20,000 2,114,496 --
</TABLE>
_____________________
(1) Cash distribution made each month since date of first distribution.
(2) Partnership closed on May 23, 1995. Wells were drilled in second
and third quarters of 1995.
(3) Partnership closed on September 11, 1995. Wells were drilled in
third and fourth quarters of 1995.
(4) Partnership closed on November 15, 1995. Wells will be drilled in
fourth quarter of 1995 and first quarter of 1996.
- 84 -
<PAGE>
Previous Drilling Activities
The following table reflects the drilling activity of previous limited
partnerships sponsored by the Managing General Partner and its Affiliates
as of November 30, 1995. All of the wells drilled were Development
Wells, except as otherwise noted.
<TABLE>
<S> <S> <S> <S> <S> <S> <S>
Productive Well Table
November 30, 1995
Gross Wells(1) Net Wells(2)
Partnership Oil Gas Dry Oil Gas Dry
Pennwest
Petroleum
Group 1984 27 13 - 27 5.5 -
Pennwest
Petroleum
Group 1985-A 14 13 1 14 7.8 .6
Petrowest
Gas Group
1986-A - 8 2 - 5.4 1
Petrowest
Gas Group
1987 - 9 1(3) - 7.1 .1(3)
Petrowest
Gas Group
1987-B - 9 1 - 5.5 .6
PDC 1987 - 7 - - 2.6 -
PDC 1988 - 5 1 - 4.1 .8
PDC 1988-B - 5 - - 4.7 -
PDC 1988-C - 9 1 - 7.0 .8
PDC 1989-P - 8 1 - 7.8 .9
PDC 1989-A - 6 1 - 5.5 .9
PDC 1989-B - 19 2 - 17.0 1.8
PDC 1990-A - 7 1 - 6.0 .9
PDC 1990-B - 11 - - 10.3 -
PDC 1990-C - 15 2 - 14.4 2.0
PDC 1990-D - 16 1 - 15.8 1.0
PDC 1991-A - 13 - - 12.0 -
PDC 1991-B - 8 2 - 7.2 2.0
- 85 -
<PAGE>
PDC 1991-C - 13 1 - 11.7 1.0
PDC 1991-D - 22 4 - 20.7 4.0
PDC 1992-A - 12 1 - 11.5 1.0
PDC 1992-B - 14 1 - 12.3 .5
PDC 1992-C - 26 3 - 24.8 2.5
PDC 1993-A - 16 1 - 14.7 1.0
PDC 1993-B - 13 2 - 12.4 2.0
PDC 1993-C - 15 2 - 13.8 2.0
PDC 1993-D - 13 2 - 12.8 2.0
PDC 1993-E - 34 2 - 33.3 2.0
PDC 1994-A - 10 - - 9.9 -
PDC 1994-B - 13 1 - 12.4 1.0
PDC 1994-C - 12 1 - 11.1 1.0
PDC 1994-D - 39 4 - 35.4 4.0
PDC 1995-A(4) - 8 1 - 7.1 1.0
PDC 1995-B(5) - 9 2 - 8.1 2.0
PDC 1995-C(6) - - - - - -
Total ...... 41 450 45 41 397.70 40.5
</TABLE>
_____________________
(1) Gross wells include all wells in which the partnerships owned a
Working Interest.
(2) Net wells are the number of gross wells multiplied by the percentage
Working Interest owned by the partnerships in the gross wells.
(3) The dry hole indicated represents an exploratory well.
(4) Partnership funded in May 1995. Wells were drilled during second
and third quarters of 1995.
(5) Partnership funded in September 1995. Wells were drilled during
third and fourth quarters of 1995.
(6) Partnership funded in November 1995. Wells will be drilled during
fourth quarter of 1995 and first quarter of 1996.
Payout and Net Cash Tables
The following tables provide information concerning the operating results
of previous limited partnerships sponsored by the Managing General Partner
and its Affiliates as of September 30, 1995.
- 86 -
<PAGE>
<TABLE>
<S> <S> <S> <S> <S>
Participants' Payout Table
November 30, 1995
Revenues Before Deducting
Operating Costs(3)
Total
Expendi-
Investors' tures Total During Three
Funds Including As of Months Ended
Invested(1) Operating November November
Costs(2) 30, 1995 30, 1995
Pennwest
Petroleum
Group 1984 $2,093,125 $3,046,315 $1,939,309 $ 8,647
Pennwest
Petroleum
Group 1985-A 1,976,250 2,844,151 1,429,150 13,200
Petrowest
Gas Group
1986-A 956,250 1,399,701 809,506 8,400
Petrowest
Gas Group
1987 1,143,250 1,684,483 1,207,730 11,514
Petrowest
Gas Group
1987-B 983,875 1,370,474 631,825 4,581
PDC 1987 454,750 654,302 420,850 3,419
PDC 1988 770,100 1,137,391 879,329 10,285
PDC 1988-B 841,500 1,171,958 426,829 6,621
PDC 1988-C 1,326,000 1,856,002 831,369 11,502
PDC 1989-P 1,523,625 2,137,680 1,292,280 17,757
PDC 1989-A 1,028,500 1,475,700 937,688 16,066
PDC 1989-B 3,153,500 4,268,113 1,899,158 27,639
PDC 1990-A 1,195,100 1,568,104 531,262 7,214
PDC 1990-B 1,887,850 2,527,276 1,077,667 20,147
PDC 1990-C 2,956,300 3,927,615 1,341,513 36,940
PDC 1990-D 3,132,674 4,121,216 1,438,898 32,431
PDC 1991-A 2,328,150 3,076,404 1,388,921 28,864
PDC 1991-B 1,583,975 2,052,596 727,694 23,851
- 87 -
<PAGE>
PDC 1991-C 2,325,600 3,027,369 1,080,569 32,631
PDC 1991-D 4,469,725 5,714,024 1,406,398 45,257
PDC 1992-A 2,472,396 3,108,269 590,034 18,099
PDC 1992-B 2,532,246 3,222,445 1,020,993 50,612
PDC 1992-C 5,430,563 6,929,688 2,218,455 132,838
PDC 1993-A 2,647,750 3,468,364 1,977,613 99,038
PDC 1993-B 2,130,620 2,569,966 535,126 36,913
PDC 1993-C 2,665,865 3,202,308 496,457 47,638
PDC 1993-D 2,545,375 3,037,140 449,539 58,103
PDC 1993-E 6,438,950 7,684,473 1,006,429 138,699
PDC 1994-A 1,798,563 2,147,558 267,219 53,786
PDC 1994-B 2,353,579 2,764,317 277,149 67,985
PDC 1994-C 2,052,636 2,392,365 216,175 61,267
PDC 1994-D 6,605,166 7,645,197 478,021 164,795
PDC 1995-A(4) 1,282,403 1,476,070 63,569 7,510
PDC 1995-B(5) 1,625,442 1,625,442 - -
PDC 1995-C(6) 1,850,184 1,850,184 - -
</TABLE>
_____________________
(1) Total Subscriptions, less commissions, management fee, and offering costs.
(2) Includes the total of the subscriptions, assessments, funds advanced by
the Managing General Partner to the general or limited partnerships,
inclusive of operating costs. None of the partnerships has borrowed
any funds.
(3) Represents the accrued gross revenues credited to the participants
from oil and gas revenues net of royalties to landowners, Overriding
Royalty Interest, and other burdens, excluding interest income.
(4) Partnership funded in May 1995; wells were drilled during second and
third quarters of 1995; first revenue distribution commenced in
October 1995.
(5) Partnership funded in September 1995; wells were drilled during
third and fourth quarters of 1995.
(6) Partnership funded in November 1995. Wells will be drilled during
fourth quarter of 1995 and first quarter of 1996.
- 88 -
<PAGE>
<TABLE>
<S> <S> <S> <S> <S> <S> <S> <S>
Participants' Net Cash Table
November 30, 1995
Total Revenues
After Deducting Cash
Operating Costs(3) Distributions(4)
Total Three Three Aggre-
Investors' Expendi- Total Months Total Months gate
Partner- Funds tures, Net As of Ended As of Ended Sect-
ship Invested of Operat- Nov. Nov. Nov. Nov. ion 29
ing Costs 30, 1995 30, 1995 30, 1995 30, 1995 Tax
(1) (2) Credit
Pennwest
Petroleum
Group
1984 $2,093,125 $2,462,500 $1,355,494 $ 811 $1,285,992 $ 811 $505,136
Pennwest
Petroleum
Group
1985-A 1,976,250 2,325,000 909,999 1,372 866,727 1,372 520,061
Petrowest
Gas Group
1986-A 956,250 1,125,000 534,805 572 508,035 572 382,395
Petrowest
Gas Group
1987 1,143,250 1,345,000 868,248 1,571 825,628 1,571 410,023
Petrowest
Gas Group
1987-B 983,875 1,157,500 418,851 900 392,481 900 306,795
PDC 1987 454,750 535,000 301,548 503 283,976 503 192,734
PDC 1988 770,100 906,000 647,938 1,354 611,049 1,354 388,674
PDC
1988-B 841,500 990,000 244,871 954 221,031 954 198,594
PDC
1988-C 1,326,000 1,560,000 535,367 1,520 492,311 1,520 375,570
PDC
1989-P 1,523,625 1,792,500 947,100 4,586 869,215 4,586 603,445
PDC
1989-A 1,028,500 1,210,000 671,989 5,133 628,905 5,133 401,720
PDC
1989-B 3,153,500 3,710,000 1,341,045 8,795 1,235,409 8,795 573,381
PDC
1990-A 1,195,100 1,406,000 369,158 1,753 308,945 1,753 99,193
- 89 -
<PAGE>
PDC
1990-B 1,887,850 2,221,000 771,391 6,174 733,631 6,174 456,304
PDC
1990-C 2,956,300 3,478,000 891,898 15,070 822,660 15,070 422,925
PDC
1990-D 3,132,674 3,685,500 1,003,182 11,130 942,315 11,130 562,960
PDC
1991-A 2,328,150 2,739,000 1,051,517 11,572 948,052 11,572 601,895
PDC
1991-B 1,583,975 1,863,500 538,598 12,067 509,723 12,067 333,567
PDC
1991-C 2,325,600 2,736,000 789,200 14,119 702,600 14,119 472,644
PDC
1991-D 4,469,725 5,258,500 950,874 19,951 877,862 19,951 581,853
PDC
1992-A 2,472,396 2,908,700 390,466 4,378 311,742 4,378 218,007
PDC
1992-B 2,532,246 2,979,100 777,648 23,496 716,591 23,496 458,335
PDC
1992-C 5,430,563 6,388,900 1,677,667 82,870 1,555,553 82,870 776,888
PDC
1993-A 2,647,750 3,026,000 1,535,249 64,313 1,341,073 64,313 59,461
PDC
1993-B 2,130,620 2,435,000 400,160 15,959 341,253 15,959 --
PDC
1993-C 2,665,865 3,046,700 340,850 25,512 284,464 25,512 --
PDC
1993-D 2,545,375 2,909,000 321,399 42,912 280,161 42,912 --
PDC
1993-E 6,438,950 7,358,800 680,757 74,317 531,809 74,317 --
PDC
1994-A 1,798,563 2,055,500 175,162 31,801 135,192 31,801 --
PDC
1994-B 2,353,579 2,689,804 202,635 46,288 147,377 46,288 __
PDC
1994-C 2,052,636 2,345,870 169,681 42,973 113,244 42,973 --
PDC
1994-D 6,605,166 7,548,761 381,585 119,157 194,730 119,157 --
PDC
1995-A
(6) 1,282,403 1,465,603 53,102 5,043 5,043 5,043 --
- 90 -
<PAGE>
PDC
1995-B
(7) 1,625,442 1,857,648 -- -- -- -- --
PDC
1995-C
(8) 1,850,184 2,114,496 -- -- -- -- --
</TABLE>
_____________________
(1) Total Subscriptions, less commissions, management fee, and offering costs.
(2) Includes the total of the subscriptions, assessments, funds advanced by
the Managing General Partner to the general or limited partnerships,
exclusive of operating costs. None of the partnerships has borrowed any
funds.
(3) Represents the accrued gross revenues credited from oil and gas production,
excluding operating costs, Landowners' Royalty Interests, Overriding
Royalty Interests, and other burdens.
(4) Represents the net cash distributed to the partnerships. All cash
distributions to the partners were made from operations and constituted
ordinary income.
(5) Wells drilled after December 31, 1992 will not qualify for the credit.
(6) Partnership funded in May 1995; wells were drilled during second and
third quarters of 1995; first revenue distribution commenced in
October 1995.
(7) Partnership funded in September 1995; wells were be drilled during
third and fourth quarters of 1995.
(8) Partnership funded in November 1995; wells will be drilled during
fourth quarter of 1995 and first quarter of 1996.
- 91 -
<PAGE>
<TABLE>
<S> <S> <S> <S>
Managing General Partner's Payout Table
November 30, 1995
Revenues Before Deducting
Operating Costs(2)
Total Total During Three
Expenditures As of Months Ended
Including November November
Partnership Operating Costs(1) 30, 1995 30, 1995
Pennwest
Petroleum
Group 1984 $ 155,921 $248,434 $ 820
Pennwest
Petroleum
Group
1985-A 144,297 190,883 1,260
Petrowest
Gas Group
1986-A 73,670 127,389 1,432
Petrowest
Gas Group
1987 88,657 183,422 1,910
Petrowest
Gas Group
1987-B 72,130 96,135 763
PDC 1987 34,437 64,466 576
PDC 1988 59,862 141,227 1,746
PDC 1988-B 61,683 69,479 1,134
PDC 1988-C 98,685 129,835 1,926
PDC 1989-P 112,509 198,128 2,951
PDC 1989-A 177,520 232,256 4,016
PDC 1989-B 470,835 450,854 6,909
PDC 1990-A 167,154 119,484 1,804
PDC 1990-B 282,688 259,453 5,036
PDC 1990-C 424,228 300,556 9,236
PDC 1990-D 435,393 303,944 8,106
PDC 1991-A 333,178 332,407 7,217
PDC 1991-B 214,598 172,139 5,962
PDC 1991-C 322,501 255,815 8,159
PDC 1991-D 584,178 305,299 9,872
- 92 -
<PAGE>
PDC 1992-A 296,250 85,543 -0-
PDC 1992-B 332,171 245,067 11,415
PDC 1992-C 714,656 517,970 28,596
PDC 1993-A 378,744 428,719 20,560
PDC 1993-B 262,801 113,691 6,888
PDC 1993-C 325,372 99,018 6,236
PDC 1993-D 308,377 92,788 9,023
PDC 1993-E 782,654 215,576 25,333
PDC 1994-A 471,922 64,775 13,446
PDC 1994-B 607,023 69,288 16,996
PDC 1994-C 524,783 54,044 15,317
PDC 1994-D 1,675,401 119,505 41,199
PDC 1995-A(3) 323,218 15,892 1,877
PDC 1995-B(4) 406,361 -- --
PDC 1995-C(5) 462,546 -- --
</TABLE>
_____________________
(1) Includes Managing General Partner share of drilling costs.
(2) Represents the accrued gross revenues credited to the managing
general partner(s).
(3) Partnership funded in May 1995; wells were drilled in second
and third quarters of 1995; first revenue distribution
October 1995.
(4) Partnership funded in September 1995; wells were drilled during
third and fourth quarters of 1995.
(5) Partnership funded in November 1995; wells will be drilled during
fourth quarter of 1995 and first quarter of 1996.
- 93 -
<PAGE>
<TABLE>
<S> <S> <S> <S> <S> <S> <S>
Managing General Partner's Net Cash Table
November 30, 1995
Total Revenues
After Deducting Cash
Operating Costs(2) Distributions(4)
Total Aggre-
Expendi- Three Three gate
tures, Net Total Months Total Months Sec-
of Operat- As of Ended As of Ended tion 29
ing Nov. 30, Nov. 30, Nov. 30, Nov. 30, Tax
Partnersip Costs(1) 1995 1995 1995 1995 Credits
(4)
Pennwest
Petroleum
Group 1984 $ 129,605 $222,117 $ 614 $218,459 $ 614 $25,904
Pennwest
Petroleum
Group
1985-A 122,368 168,954 949 166,677 949 26,670
Petrowest
Gas Group
1986-A 59,210 112,929 1,020 108,489 1,020 20,126
Petrowest
Gas Group
1987 70,789 165,554 1,387 159,342 1,387 21,580
Petrowest
Gas Group
1987-B 60,921 84,926 570 80,551 570 16,147
PDC 1987 28,158 58,187 423 55,543 423 10,144
PDC 1988 47,684 129,050 1,276 123,501 1,276 20,457
PDC 1988-B 52,105 59,900 835 55,293 835 10,452
PDC 1988-C 82,105 113,256 1,401 105,939 1,401 19,767
PDC 1989-P 94,342 179,960 2,258 166,572 2,258 31,760
PDC 1989-A 114,278 169,015 1,406 158,244 1,406 100,430
PDC 1989-B 350,389 330,408 2,342 303,999 2,342 143,345
PDC 1990-A 132,789 85,120 440 70,067 440 24,798
PDC 1990-B 209,761 186,525 1,611 177,085 1,611 114,076
PDC 1990-C 328,478 204,807 3,820 187,497 3,820 105,731
PDC 1990-D 348,075 216,626 2,921 201,409 2,921 140,740
- 94 -
<PAGE>
PDC 1991-A 258,683 257,912 3,044 232,046 3,044 150,474
PDC 1991-B 175,997 133,539 3,165 127,764 3,165 83,392
PDC 1991-C 258,400 191,714 3,695 170,064 3,695 118,161
PDC 1991-D 496,639 217,760 4,201 199,507 4,201 145,463
PDC 1992-A 274,711 64,004 -0- 44,323 -0- 54,502
PDC 1992-B 281,361 194,257 6,070 182,046 6,070 114,584
PDC 1992-C 603,396 406,711 20,261 382,289 20,261 194,222
PDC 1993-A 294,194 344,168 14,661 301,544 14,661 13,052
PDC 1993-B 236,736 87,626 3,637 74,695 3,637 --
PDC 1993-C 296,207 69,853 3,468 57,476 3,468 --
PDC 1993-D 282,819 67,229 7,190 58,177 7,190 --
PDC 1993-E 715,438 148,361 15,127 115,665 15,127 --
PDC 1994-A 449,641 42,493 7,950 33,719 7,950 --
PDC 1994-B 588,395 50,659 11,572 36,844 11,572 --
PDC 1994-C 513,159 42,420 10,743 28,311 10,743 --
PDC 1994-D 1,651,292 95,396 29,789 48,682 29,789 --
PDC 1995-A(5) 320,601 13,276 1,261 1,261 1,261 --
PDC 1995-B(6) 406,361 -- -- -- -- --
PDC 1995-C(7) 462,546 -- -- -- -- --
</TABLE>
_____________________
(1) Includes Managing General Partner share of drilling costs, exclusive
of operating costs.
(2) Represents the accrued gross revenues credited from oil and gas
production, excluding operating costs, landowners' royalty
interests, Overriding Royalty Interests, and other burdens.
(3) Represents the net cash received from the partnerships' cash
distributions. All cash distributions to the managing general
partner were made from operations.
(4) Wells drilled after December 31, 1992 will not qualify for the credit.
(5) Partnership funded in May 1995; wells were drilled during second and
third quarters of 1995; first revenue distribution commenced in
October 1995.
(6) Partnership funded in September 1995; wells were drilled during
third and fourth quarters of 1995.
(7) Partnership funded in November 1995; wells will be drilled during
fourth quarter of 1995 and first quarter of 1996.
- 95 -
<PAGE>
Tax Deductions and Tax Credits of Participants in Previous Partnerships
The following table reflects the participants' share of the previous
limited partnerships' available tax deductions that were reported in the
partnerships' tax returns and such share of tax deductions as a percentage
of their subscriptions. The following percentages do not reflect the
effect of the revenues from the partnerships' operations and are subject
to audit adjustments by the Service. The table also reflects the
aggregate Section 29 nonconventional fuel production credit as a
percentage of the participants' initial investment over the life of each
partnership through November 30, 1995, and the federal tax savings from
deductions and tax credits based on the maximum marginal tax rate in each
year. Wells drilled after December 31, 1992 will not qualify for the
credit. The final column shows these tax shelter ratios calculated in
accordance with Service regulations. Programs with anticipated tax
shelter ratios of greater than 2:1 in any of the first five years must
register as tax shelters. The Managing General Partner does not expect
any of the prior partnerships or the Partnerships in the current Program
to exceed the 2:1 ratio. The following table is based on past experience
and should not be considered as necessarily indicative of the results that
may be expected in these Partnerships. It is suggested that prospective
subscribers consult with their tax advisors concerning their specific tax
circumstances and the tax benefits available to them individually, which
may materially vary in various circumstances.
- 96 -
<PAGE>
<TABLE>
<S> <S> <S> <S> <S> <S>
Estimated
First Aggregate Aggregate Federal Tax
Year Tax Deductions Section 29 Tax Shelter
Deductions Thereafter Tax Savings(2) Ratio(3)
Credits(1)
*Pennwest
Petroleum
Group 1984 70.87% 22.07% 21.30% 67.80% 1.4:1
*Pennwest
Petroleum
Group 1985-A 69.51% 25.32% 22.40% 69.80% 1.4:1
*Petrowest
Gas Group
1986-A 70.10% 27.79% 34.00% 82.90% 1.7:1
*Petrowest
Gas Group
1987 64.60% 31.78% 30.50% 78.70% 2.0:1
*Petrowest
Gas Group
1987-B 68.70% 26.30% 26.50% 74.00% 1.9:1
*PDC 1987 70.30% 28.71% 36.00% 85.50% 2.3:1
*PDC 1988 72.60% 29.71% 42.90% 83.80% 2.5:1
*PDC 1988-B 66.70% 28.32% 20.10% 58.00% 1.7:1
*PDC 1988-C 69.20% 25.93% 24.10% 62.10% 1.8:1
*PDC 1989-P 71.10% 28.05% 33.70% 66.30% 2.2:1
*PDC 1989-A 69.80% 23.91% 33.20% 64.10% 2.1:1
*PDC 1989-B 69.10% 24.51% 15.50% 46.30% 1.5:1
*PDC 1990-A 70.90% 15.90% 7.10% 35.70% 1.1:1
*PDC 1990-B 71.50% 20.85% 20.50% 50.90% 1.6:1
*PDC 1990-C 70.60% 17.78% 12.20% 41.30% 1.3:1
PDC 1990-D 69.70% 18.68% 15.30% 44.40% 1.4:1
PDC 1991-A 69.80% 18.07% 22.00% 49.20% 1.6:1
PDC 1991-B 67.00% 16.01% 17.90% 43.60% 1.5:1
PDC 1991-C 69.60% 16.39% 17.30% 43.90% 1.5:1
PDC 1991-D 69.80% 15.15% 11.10% 37.40% 1.2:1
PDC 1992-A 73.10% 11.45% 7.50% 33.60% 1.1:1
PDC 1992-B 69.60% 17.02% 15.40% 42.10% 1.4:1
- 97 -
<PAGE>
PDC 1992-C 69.20% 16.78% 12.20% 38.70% 1.3:1
PDC 1993-A 69.00% 22.55% -- 28.20% 0.9:1
PDC 1993-B 68.10% 11.87% -- 29.00% 0.8:1
PDC 1993-C 68.80% 10.04% -- 28.20% 0.8:1
PDC 1993-D 68.60% 7.83% -- 27.40% 0.8:1
PDC 1993-E 67.60% 9.19% -- 27.50% 0.8:1
PDC 1994-A 87.70% 1.76% -- 35.40% 0.9:1
PDC 1994-B 89.40% 1.27% -- 35.90% 0.9:1
PDC 1994-C 89.70% 1.35% -- 36.00% 0.9:1
PDC 1994-D 89.90% 1.03% -- 35.90% 0.9:1
PDC 1995-A(4) 90.00% -- -- 35.70% 0.9:1
PDC 1995-B(5) 90.00% -- -- 35.70% 0.9:1
PDC 1995-C(6) 90.00% -- -- 35.70% 0.9:1
</TABLE>
*Partnerships in existence for over five years.
_____________________
(1) Wells drilled after December 31, 1992 will not qualify for the credit.
(2) The Estimated Federal Tax Savings column reflects the percentage
savings in taxes which would have been paid by an investor had he
not had the use of the various deductions and credits available to
a Partner in the Program and it assumes full use of deductions and
tax credits at maximum Federal tax rates of 50% in 1984-1986, 40% in
1987 and 1988, and 33% in 1989 and 1990, 31% in 1991-1992, 36% in
1993, and 39.6% in 1994 and thereafter.
(3) Total deductions plus 200% of credits generated for partnerships
first offered before December 31, 1986. Total deductions plus 350%
of credits generated for partnerships offered after December 31, 1986.
(4) Partnership funded in May 1995.
(5) Partnership funded in September 1995.
(6) Partnership funded in November 1995.
- 98 -
<PAGE>
<TABLE>
<S> <S> <S> <S> <S> <S> <S>
Percentage of Return on Subscriptions Through
November 30, 1995
From Cash Distributions, Tax Savings from
Deductions and Tax Credits(1)
Fed. Tax Total Years/
Cash Cumula- Total Deduc- Return of Months
Distribu tive Cash tions Cash, Tax All wells
-tions Section 29 & Tax Tax Deduction Producing
Credit Credit Effected
(2) (4) (3) (5)
*Pennwest
Petroleum
Group 1984 52.20% 21.30% 73.50% 46.50% 120.00% 9/10
*Pennwest
Petroleum 37.10% 22.40% 59.50% 47.40% 106.90% 9/6
Group 1985-A
**Petrowest
Gas Group 45.00% 34.00% 79.00% 48.90% 127.90% 8/5
1986
**Petrowest
Gas Group 61.30% 30.50% 91.80% 48.20% 140.00% 7/8
1987
**Petrowest
Gas Group
1987-B 33.90% 26.50% 60.40% 47.50% 107.90% 7/5
**PDC 1987 52.90% 36.00% 88.40% 49.50% 138.40% 7/3
**PDC 1988 67.00% 42.90% 109.90% 40.90% 150.80% 6/9
**PDC 1988-B 22.30% 20.10% 42.40% 37.90% 80.30% 6/5
**PDC 1988-C 31.60% 24.10% 55.70% 38.00% 93.70% 6/3
**PDC 1989-P 48.20% 33.70% 81.90% 32.60% 114.50% 5/9
**PDC 1989-A 52.00% 33.20% 85.20% 30.90% 116.10% 5/5
**PDC 1989-B 33.30% 15.50% 48.80% 30.80% 79.60% 5/3
**PDC 1990-A 22.00% 7.10% 29.10% 28.60% 57.70% 4/10
**PDC 1990-B 33.00% 20.50% 53.50% 30.40% 83.90% 4/8
**PDC 1990-C 23.70% 12.20% 35.90% 29.10% 65.00% 4/4
**PDC 1990-D 25.60% 15.30% 40.90% 29.10% 70.00% 4/3
**PDC 1991-A 34.70% 22.00% 56.70% 27.20% 83.90% 3/10
**PDC 1991-B 27.40% 17.90% 45.30% 25.70% 71.00% 3/7
**PDC 1991-C 25.70% 17.30% 43.00% 26.60% 69.60% 3/5
- 99 -
<PAGE>
**PDC 1991-D 16.70% 11.10% 27.80% 26.30% 54.10% 3/3
**PDC 1992-A 10.70% 7.50% 18.20% 26.10% 44.30% 2/10
**PDC 1992-B 24.10% 15.40% 39.50% 26.70% 66.20% 2/8
**PDC 1992-C 24.30% 12.20% 36.50% 26.50% 63.00% 2/5
**PDC 1993-A 44.30% -- 44.30% 28.20% 72.50% 2/3
**PDC 1993-B 14.00% -- 14.00% 29.00% 43.00% 1/10
**PDC 1993-C 9.30% -- 9.30% 28.20% 37.50% 1/7
**PDC 1993-D 9.60% -- 9.60% 27.40% 37.00% 1/5
**PDC 1993-E 7.20% -- 7.20% 27.50% 34.70% 1/2
**PDC 1994-A 6.60% -- 6.60% 35.40% 42.00% 0/10
**PDC 1994-B 5.50% -- 5.50% 35.90% 41.40% 0/7
**PDC 1994-C 4.80% -- 4.80% 36.00% 40.80% 0/6
**PDC 1994-D 2.60% -- 2.60% 35.90% 38.50% 0/3
**PDC 1995-A(6) 0.30% -- .30% 35.70% 36.00% 0
PDC 1995-B(7) -- -- -- 35.70% 35.70% 0
PDC 1995-C(8) -- -- -- 35.70% 35.70% 0
* Program contains oil & gas production
** Program contains gas production
</TABLE>
_____________________
(1) This table assumes investors were able to fully utilize all tax
benefits at the maximum marginal Federal rate.
(2) Cash distributions to investors divided by investors' initial
investment.
(3) Federal tax savings from deductions assuming investor is in the
highest marginal bracket. Rates used were 50% in 1984, 1985 and
1986, 38.5% in 1987, 33% in 1988, 1989 and 1990, 31% in 1991 and
1992, 36% in 1993, and 39.6% in 1994 and thereafter.
(4) Credit earned on qualified production. 1995 credit estimated.
Wells drilled after December 31, 1992 will not qualify for the
credit.
(5) This column represents the sum of the percentage amounts set forth
in the first three columns of this table.
(6) Partnership funded in May 1995; wells were drilled during second and
third quarters of 1995.
(7) Partnership funded in September 1995; wells were drilled during
third and fourth quarters of 1995.
(8) Partnership funded in November 1995; wells will be drilled during
fourth quarter of 1995 and first quarter of 1996.
- 100 -<PAGE>
Partnership Proved Reserves and Future Net Revenues
The following table presents information regarding the public drilling
programs sponsored by the Managing General Partner. The table reflects
with respect to each partnership the proved reserves and future net
reserves as of January 1, 1995. The information presented has been
derived from reports prepared by an independent petroleum consultant,
Wright & Company, Inc., except for PDC 1992-A Limited Partnership which
was prepared by the Managing General Partner's petroleum engineer.
<TABLE>
<S> <S> <S> <S> <S> <S> <S>
Partnership Proved Reserves and Future Net Revenues
as of January 1, 1995(1)
Percent
Value
Net Oil BBL Net Gas Estimated
Discounted
Category of Reserves Reserves Future Net at 10%
Per
Partnership Proved Reserves BBL MCF Revenues Annum
PDC 1989-A Proved Developed 5,422 1,120,058 $ 1,694,842 $ 766,006
Proved Undeveloped - - -- -- --
Totals 5,422 1,120,058 $ 1,694,842 $ 766,006
PDC 1989-B Proved Developed -- 1,678,965 $ 2,110,950 $1,051,056
Proved Undeveloped -- -- -- --
Totals -- 1,678,965 $ 2,110,950 $1,051,056
PDC 1990-A Proved Developed -- 320,528 $ 324,381 $ 176,130
Proved Undeveloped -- -- -- --
Totals -- 320,528 $ 324,381 $ 176,130
PDC 1990-B Proved Developed -- 1,371,976 $ 1,860,346 $ 915,331
Proved Undeveloped -- -- -- --
Totals -- 1,371,976 $ 1,860,346 $ 915,331
PDC 1990-C Proved Developed -- 1,981,906 $ 2,541,881 $1,292,985
Proved Undeveloped -- -- -- --
Totals -- 1,981,906 $ 2,541,881 $1,292,985
PDC 1990-D Proved Developed -- 2,220,357 $ 2,841,649 $1,479,905
Proved Undeveloped -- -- -- --
Totals -- 2,220,357 $ 2,841,649 $1,479,905
PDC 1991-A Proved Developed -- 1,586,845 $ 2,063,242 $1,035,738
Proved Undeveloped -- -- -- --
Totals -- 1,586,845 $ 2,063,242 $1,035,738
PDC 1991-B Proved Developed -- 1,192,984 $ 1,570,479 $ 780,656
Proved Undeveloped -- -- -- --
Totals -- 1,192,984 $ 1,570,479 $ 780,656
- 101 -
<PAGE>
PDC 1991-C Proved Developed -- 2,014,158 $ 2,647,762 $1,281,640
Proved Undeveloped -- -- -- --
Totals -- 2,014,158 $ 2,647,762 $1,281,640
PDC 1991-D Proved Developed 377 2,308,377 $ 2,879,823 $1,444,541
Proved Undeveloped -- -- --
Totals 377 2,308,377 $ 2,879,823 $1,444,541
PDC 1992-A Proved Developed -- 870,264 $ 982,229 $ 460,979
Proved Undeveloped -- -- -- --
Totals -- 870,264 $ 982,229 $ 460,979
PDC 1992-B Proved Developed -- 2,903,736 $ 3,921,287 $1,805,700
Proved Undeveloped -- -- -- --
Totals -- 2,903,736 $ 3,921,287 $1,805,700
- 98 -
PDC 1992-C Proved Developed 1,227 4,966,710 $ 6,653,810 $3,287,995
Proved Undeveloped -- -- -- --
Totals 1,227 4,966,710 $ 6,653,810 $3,287,995
PDC 1993-A Proved Developed -- 3,997,786 $ 6,000,663 $2,863,037
Proved Undeveloped -- -- -- --
Totals -- 3,997,786 $ 6,000,663 $2,863,037
PDC 1993-B Proved Developed -- 1,681,718 $ 2,219,474 $1,081,879
Proved Undeveloped -- -- -- --
Totals -- 1,681,718 $ 2,219,474 $1,081,879
PDC 1993-C Proved Developed -- 2,377,119 $ 3,345,079 $1,579,394
Proved Undeveloped -- -- -- --
Totals -- 2,377,119 $ 3,345,079 $1,579,394
PDC 1993-D Proved Developed 3,240 1,982,865 $ 2,914,858 $1,377,883
Proved Undeveloped -- -- -- --
Totals 3,240 1,982,865 $ 2,914,858 $1,377,883
PDC 1993-E Proved Developed 11,959 6,589,612 $ 9,978,410 $4,526,058
Proved Undeveloped -- -- --
Totals 11,959 6,589,612 $ 9,978,410 $4,526,058
PDC 1994-A Proved Developed -- 1,836,949 $ 2,912,989 $1,346,478
Proved Undeveloped -- -- -- --
Totals -- 1,836,949 $ 2,912,989 $1,346,478
PDC 1994-B Proved Developed -- 2,412,251 $ 3,364,574 $1,759,752
Proved Undeveloped -- -- -- --
Totals -- 2,412,251 $ 3,364,574 $1,759,752
PDC 1994-C Proved Developed -- 2,078,926 $ 3,090,056 $1,519,836
Proved Undeveloped -- -- -- --
Totals -- 2,078,926 $ 3,090,056 $1,519,836
PDC
1994-D(2) Proved Developed -- -- -- --
Proved Undeveloped -- -- -- --
Totals -- -- -- --
PDC
1995-A(2) Proved Developed -- -- -- --
Proved Undeveloped -- -- -- --
Totals -- -- -- --
- 102 -
<PAGE>
PDC
1995-B(2) Proved Developed -- -- -- --
Proved Undeveloped -- -- -- --
Totals -- -- -- --
PDC
1995-C(2) Proved Developed -- -- -- --
Proved Undeveloped -- -- -- --
Totals -- -- -- --
</TABLE>
____________________
(1) For the Partnerships PDC 1989-A through PDC 1992-C, the Managing
General Partner owns 20% of the reserves listed and the Investor
Partners own 80% of the reserves listed above. In the PDC 1993-A,
PDC 1993-B, PDC 1993-C, PDC 1993-D and PDC 1993-E Limited
Partnerships, the Managing General Partner owns 18% of the reserves
listed and the Investor Partners own 82% of the reserves listed
above. In the PDC 1994-A, PDC 1994-B, PDC 1994-C, PDC 1994-D, PDC
1995-A, and PDC 1995-B Limited Partnerships, the Managing General
Partner owns 20% of the reserves listed and the Investor Partners
own 80% of the reserves listed above.
(2) The wells of this Partnership were drilled after December 31, 1994;
therefore, reserve studies have not been conducted.
TAX CONSIDERATIONS
The full tax opinion of Metzger, Hollis, Gordon & Mortimer is attached
to the Prospectus as Appendix D. All prospective investors should review
Appendix D in its entirety before investing in the Program. All
references in this "Tax Considerations" section are to the tax opinion set
forth in Appendix D.
The following is a summary of the opinions of Metzger, Hollis, Gordon
& Mortimer, counsel to the Partnerships (collectively, the "Partnership"),
which represent counsel's opinions on all material federal income tax
consequences to the Partnership and to the Investor Partners. There may
be aspects of a particular investor's tax situation which are not
addressed in the following discussion or in Appendix D. Additionally, the
resolution of certain tax issues depends upon future facts and
circumstances not known to counsel as of the date of this Prospectus;
thus, no assurance as to the final resolution of such issues should be
drawn from the following discussion.
The following statements are based upon the provisions of the Internal
Revenue Code of 1986, as amended (the "Code"), including revisions to the
Code effected by the Revenue Reconciliation Act of 1990 (the "1990 Act"),
the Omnibus Budget Reconciliation Act of 1990, the Energy Policy Act of
1992 (the "Energy Act"), the Revenue Reconciliation Act of 1993 (the "RRA
93"), and the Uruguay Round Agreements Act ("GATT"), existing and proposed
regulations thereunder, current administrative rulings, and court
decisions. It is possible that legislative or administrative changes or
future court decisions may significantly modify the statements and
opinions expressed herein. Such changes could be retroactive with respect
to the transactions prior to the date of such changes.
Moreover, uncertainty exists concerning some of the federal income tax
aspects of the transactions being undertaken by the Partnership. Some of
the tax positions being taken by the Partnership may be challenged by the
Internal Revenue Service (the "Service") and any such challenge could be
successful. Thus, there can be no assurance that all of the anticipated
tax benefits of an investment in the Partnership will be realized.
- 103 -
<PAGE>
Counsel's opinion is based upon the transactions described in this
Prospectus (the "Transaction") and upon facts as they have been
represented to counsel or determined by it as of the date of the opinion.
Any alteration of the facts may adversely affect the opinions rendered.
It is possible, however, that some of the tax benefits will be eliminated
or deferred to future years.
Because of the factual nature of the inquiry, and in certain cases the
lack of clear authority in the law, it is not possible to reach a judgment
as to the outcome on the merits (either favorable or unfavorable) of
certain material federal income tax issues as described more fully herein.
Summary of Conclusions
Opinions expressed: The following is a summary of the specific
opinions expressed by counsel with respect to Tax Considerations discussed
herein.
TO BE FULLY UNDERSTOOD, THE COMPLETE DISCUSSION OF THESE MATTERS SET FORTH
IN THE FULL TAX OPINION IN APPENDIX D SHOULD BE READ BY EACH PROSPECTIVE
INVESTOR PARTNER.
1. The material federal income tax benefits in the aggregate from an
investment in the Partnership will be realized.
2. The Partnership will be treated as a partnership for federal income
tax purposes and not as a corporation and not as association taxable as a
corporation. See "Partnership Status;" "Federal Taxation of
Partnerships."
3. To the extent the Partnership's wells are timely drilled and amounts
are timely paid, the Partners will be entitled to their pro rata share of
the Partnership's IDC paid in 1996 with respect to the Partnerships
designated "PDC 1996-_ Limited Partnership" and in 1997 with respect to
the Partnerships designated "PDC 1997-_ Limited Partnership." See
"Intangible Drilling and Development Costs Deductions."
4. Neither the at risk nor the adjusted basis rules will limit the
deductibility of losses generated from the Partnership. See "Basis and At
Risk Limitations."
5. Additional General Partners' interests will not be considered a
passive activity within the meaning of Code Section 469 and losses
generated while such general partner interest is so held will not be
limited by the passive activity provisions. See "Passive Loss and Credit
Limitations."
6. Limited Partners' interests (other than those held by Additional
General Partners who convert their interests into Limited Partners'
interests) will be considered a passive activity within the meaning of
Code Section 469 and losses generated therefrom will be limited by the
passive activity provisions. See "Passive Loss and Credit Limitations."
7. The Partnership will not be terminated solely as the result of the
conversion of Partnership interests. See "Conversion of Interests."
8. To the extent provided herein, the Partners' distributive shares of
Partnership tax items will be determined and allocated substantially in
accordance with the terms of the Partnership Agreement. See "Partnership
Allocations."
- 104 -
<PAGE>
9. The Partnership will not be required to register with the Service as
a tax shelter. See "Registration as a Tax Shelter."
No opinion expressed: Due to the lack of authority, or the essentially
factual nature of the question, counsel expresses no opinion on the
following:
1. The impact of an investment in the Partnership on an Investor's
alternative minimum tax, due to the factual nature of the issue. See
"Alternative Minimum Tax."
2. Whether, under Code Section 183, the losses of the Partnership will
be treated as derived from "activities not engaged in for profit," and
therefore nondeductible from other gross income, due to the inherently
factual nature of a Partner's interest and motive in engaging in the
Transaction. See "Profit Motive."
3. Whether each Partner will be entitled to percentage depletion since
such a determination is dependent upon the status of the Partner as an
independent producer and on the Partner's other oil and gas production.
Due to the inherently factual nature of such a determination, counsel is
unable to render an opinion as to the availability of percentage
depletion. See "Depletion Deductions."
4. Whether any interest incurred by a Partner with respect to any
borrowings will be deductible or subject to limitations on deductibility,
due to the factual nature of the issue. Without any assistance of the
Managing General Partner or any of its affiliates, some Partners may
choose to borrow the funds necessary to acquire a Unit and may incur
interest expense in connection with those loans. Based upon the purely
factual nature of any such loans, counsel is unable to express an opinion
with respect to the deductibility of any interest paid or incurred
thereon. See "Interest Deductions."
5. Whether the fees to be paid to the Managing General Partner and to
third parties will be deductible, due to the factual nature of the issue.
Due to the inherently factual nature of the proper allocation of expenses
among nondeductible syndication expenses, amortizable organization
expenses, amortizable "start-up" expenditures, and currently deductible
items, and because the issues involve questions concerning both the nature
of the services performed and to be performed and the reasonableness of
amounts charged, counsel is unable to express an opinion regarding such
treatment. See "Transaction Fees."
General Information: Certain matters contained herein are not
considered to address a material tax consequence and are for general
information, including the matters contained in sections dealing with gain
or loss on the sale of Units or of Property, Partnership distributions,
tax audits, penalties, and state, local, and self-employment tax. See
"General Tax Effects of Partnership Structure," "Gain or Loss on Sale of
Properties or Units," "Partnership Distributions," "Administrative
Matters," "Accounting Methods and Periods," "Social Security Benefits;
Self-Employment Tax," and "State and Local Tax."
Facts and Representations: The opinions of counsel are also based upon
the facts described in this Prospectus and upon certain representations
made to it by the Managing General Partner for the purpose of permitting
counsel to render its opinions, including the following representations
with respect to the program:
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1. The Partnership Agreement to be entered into by and among the Managing
General Partner and Investor Partners and any amendments thereto will
be duly executed and will be made available to any Investor Partner
upon written request. The Partnership Agreement will be duly recorded
in all places required under the West Virginia Uniform Limited
Partnership Act (the "Act") for the due formation of the Partnership
and for the continuation thereof in accordance with the terms of the
Partnership Agreement. The Partnership will at all times be operated
in accordance with the terms of the Partnership Agreement, the
Prospectus, and the Act.
2. No election will be made by the Partnership, Investor Partners, or
Managing General Partner to be excluded from the application of the
provisions of Subchapter K of the Code.
3. The Partnership will own an operating mineral interest, as defined in
the Code and in the Regulations, in all of the Drill Sites and none of
the Partnership's revenues will be from non-working interests.
4. The Investor Partners will not own, directly or indirectly,
individually or in the aggregate, more than twenty percent (20%) of the
shares of the Managing General Partner, or of any affiliate (as that
term is defined in Code Section 1504(a) and determined by application
of the attribution rules of Code Section 318).
5. The Managing General Partner will be independent of the Investor
Partners and will not be merely a "dummy" acting as an agent for the
Investor Partners. The Managing General Partner has and will continue
to have at all times during the existence of the Partnership a net
worth in excess of $5,000,000 (excluding its interest in the
Partnership or any other limited partnership).
6. The respective amounts that will be paid to the General Partners as
Drilling Fees, Operating Fees, and other fees will be amounts that
would not exceed amounts that would be ordinarily paid for similar
transactions between Persons having no affiliation and dealing with
each other at "arms' length."
7. The Managing General Partner will cause the Partnership to properly
elect to deduct currently all Intangible Drilling and Development
Costs.
8. The Partnership will have a December 31 taxable year and will report
its income on the accrual basis.
9. The Drilling and Operating Agreement to be entered into by and among
the Managing General Partner and the Partnership will be duly executed
and will govern the drilling of the Partnership's Wells. All
Partnership wells will be spudded by not later than March 30, 1997 for
Partnerships designated "PDC 1996-_ Limited Partnership" and March 30,
1998 for Partnerships designated "PDC 1997-_ Limited Partnership." The
entire amount to be paid to the Managing General Partner under the
Drilling and Operating Agreement is attributable to Intangible Drilling
and Development Costs and does not include a profit for services
performed or materials provided by third parties which are passed
through at actual cost.
10. The Drilling and Operating Agreement will be duly executed and will
govern the operation of the Partnership's Wells.
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11. Based upon the Managing General Partner's review of its experience
with its previous drilling programs for the past several years and
upon the intended operations of the Partnership, the Managing
General Partner believes that the sum of (i) the aggregate
deductions, including depletion deductions, and (ii) 350 percent of
the aggregate credits from the Partnership will not, as of the close
of any of the first five years ending after the date on which Units
are offered for sale, exceed two times the cash invested by the
Partners in the Partnership as of such dates. In that regard, the
Managing General Partner has reviewed the economics of its similar
oil and gas drilling programs for the past several years, and has
represented that it has determined that none of those programs has
resulted in a tax shelter ratio greater than two to one. Further,
the Managing General Partner has represented that the deductions that
are or will be represented as potentially allowable to an investor will
not result in any Partnership having a tax shelter ratio greater than
two to one and believes that no person could reasonably infer from
representations made, or to be made, in connection with the offering
of Units that such sums as of such dates will exceed two times the
Partners' cash investments as of such dates.
12. The Managing General Partner believes that at least 90% of the gross
income of the Partnership will constitute income derived from the
exploration, development, production, and/or marketing of oil and
gas. The Managing General Partner does not believe that any market
will ever exist for the sale of Units. Further, the Units will not
be traded on an established securities market.
13. The Partnership and each Partner will have the objective of carrying
on business for profit and dividing the gain therefrom.
14. The Managing General Partner does not anticipate the purchase of
Units by tax-exempt investors or foreign investors.
The opinions of counsel are also subject to all the assumptions,
qualifications, and limitations set forth in the following discussion and
in the opinion, including the assumptions that each of the Partners has
full power, authority, and legal right to enter into and perform the terms
of the Partnership Agreement and to take any and all actions thereunder in
connection with the transactions contemplated thereby.
Each prospective Investor should be aware that, unlike a ruling from
the Service, an opinion of counsel represents only such counsel's best
judgment. THERE CAN BE NO ASSURANCE THAT THE SERVICE WILL NOT
SUCCESSFULLY ASSERT POSITIONS WHICH ARE INCONSISTENT WITH THE OPINIONS OF
COUNSEL SET FORTH IN THIS DISCUSSION AND APPENDIX D OR IN THE TAX
REPORTING POSITIONS TAKEN BY THE PARTNERS OR THE PARTNERSHIP. EACH
PROSPECTIVE INVESTOR SHOULD CONSULT HIS OWN TAX ADVISOR TO DETERMINE THE
EFFECT OF THE TAX ISSUES DISCUSSED HEREIN AND IN APPENDIX D ON HIS
INDIVIDUAL TAX SITUATION.
General Tax Effects of Partnership Structure
Each Partnership will be formed as a limited partnership pursuant to
the Partnership Agreement and the laws of the State of West Virginia.
NO TAX RULING WILL BE SOUGHT FROM THE SERVICE AS TO THE STATUS OF THE
PARTNERSHIP AS A PARTNERSHIP FOR FEDERAL INCOME TAX PURPOSES.
- Any tax benefits anticipated from an investment in a Partnership
would be adversely affected or eliminated if the Partnership is
treated as a corporation for federal income tax purposes.
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- While counsel has opined that the Partnership will initially be
treated as a partnership for federal tax purpose, that opinion is
not binding on the Service.
The applicability of the federal income tax consequences described
herein depends on the treatment of the Partnerships as partnerships for
federal income tax purposes and not as corporations and not as
associations taxable as corporations. Any tax benefits anticipated from
an investment in a Partnership would be adversely affected or eliminated
if the Partnership is treated as a corporation for federal income tax
purposes.
Counsel to the Partnership is of the opinion that, at the time of its
formation, each of the Partnerships will be treated as a partnership for
federal income tax purposes. The opinion is based on the provisions of
the Partnership Agreement and applicable state law and representations
made by the Managing General Partner. The opinion of counsel is not
binding on the Service and is based on existing law, which is to a great
extent the result of administrative and judicial interpretation. In
addition, no assurance can be given that a Partnership will not lose
partnership status as a result of changes in the manner in which it is
operated or other facts upon which the opinion of counsel is based.
Under the Code, a partnership is not a taxable entity and, accordingly,
incurs no federal income tax liability. Rather, a partnership is a "pass-
through" entity which is required to file an information return with the
Service. In general, the character of a partner's share of each item of
income, gain, loss, deduction, and credit is determined at the partnership
level. Each partner is allocated a distributive share of such items in
accordance with the partnership agreement and is required to take such
items into account in determining the partner's income. Each partner
includes such amounts in income for any taxable year of the partnership
ending within or with the taxable year of the partner, without regard to
whether the partner has received or will receive any cash distributions
from the Partnership.
Intangible Drilling and Development Costs Deductions
- Provided drilling is completed in a timely manner, investors will
have the option of deducting their proportionate share of IDC in
1996 for Partnerships designated "PDC 1996-_ Limited Partnership"
and in 1997 for Partnerships designated "PDC 1997-_ Limited
Partnership" or capitalizing it and deducting it over a 60-month
period from the date of investment.
- 87% of Subscriptions will be utilized for IDC, which is deductible
in the year of investment against any form of income (by Additional
General Partners) or passive income (by Limited Partners); a one
Unit investor in a 39.6% marginal federal income tax bracket would
reduce his taxes payable by $6,890.
Congress granted to the Treasury Secretary the authority to prescribe
regulations that would allow taxpayers the option of deducting, rather
than capitalizing, intangible drilling and development costs ("IDC"). The
Secretary's rules state that, in general, the option to deduct IDC applies
only to expenditures for drilling and development items that do not have
a salvage value.
The Prospectus provides that 87% of the Investor Partners' capital
contributions (i.e, Subscriptions net of Dealer Manager commissions,
discounts, due diligence expenses, and wholesaling costs and the
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Management Fee) will be utilized for IDC, which is deductible in the year
of investment. As a result, Additional General Partners will realize a
deduction of 87% of their investment against any form of income in the
year in which the investment is made, provided wells are spudded within
the first 90 days of the following year. The deduction by Limited
Partners will be restricted to passive income. Based on an 87% deduction,
a one Unit ($20,000) investor in a 39.6% marginal Federal tax bracket
would reduce taxes payable by $6,890. The investor could also realize
additional tax savings on state income taxes in many states.
A. Classification of Costs
In general, IDC consists of those costs which in and of themselves have
no salvage value. In previous partnerships intangible drilling costs have
ranged from 64.6% to 89.9% of the investor's contributions. While the
planned activities of the Partnership are similar in nature to those of
prior partnerships, the amount of expenditures classified as IDC could be
greater than or less than prior partnerships. In addition, a
partnership's classification of a cost as IDC is not binding on the
government, which might reclassify an item labelled as IDC as a cost which
must be capitalized. To the extent not deductible, such amounts will be
included in the Partnership's basis in mineral property and in the
Partners' bases of their interests in the Partnership.
B. Timing of Deductions
Although the Partnership will elect to deduct IDC, each investor has an
option of deducting IDC, or capitalizing all or a part of the IDC and
amortizing it on a straight-line basis over a sixty-month period,
beginning with the taxable month in which the expenditure is made. In
addition to the effect of this change on regular taxable income, the two
methods have different treatment under the AMT (see "Alternative Minimum
Tax").
In order for the IDC to qualify for deduction in 1996, the wells for
Partnerships designated "PDC 1996-_ Limited Partnership" must be spudded
by March 30, 1997; in order for the IDC to qualify for deduction in 1997,
the wells for Partnerships designated "PDC 1997-_ Limited Partnership"
must be spudded by March 30, 1998; in each case certain other requirements
must be met. Although PDC will attempt to satisfy each requirement of the
Service and judicial authority for deductibility of IDC in 1996 for
Partnerships designated "PDC 1996-_ Limited Partnership (or in 1997 for
Partnerships designated "PDC 1997-_ Limited Partnership"), no assurance
can be given that the Service will not successfully contend that the IDC
of a well which is not completed until 1997 for Partnerships designated
"PDC 1996-_ Limited Partnership" (or 1998 for Partnerships designated "PDC
1997-_ Limited Partnership") are not deductible in whole or in part until
1997 for Partnerships designated "PDC 1996-_ Limited Partnership" (or 1998
for Partnerships designated "PDC 1997-_ Limited Partnership"). Further,
to the extent drilling of the Partnership's wells does not commence by
March 30, 1997 for Partnerships designated "PDC 1996-_ Limited
Partnership" (or March 30, 1998 for Partnerships designated "PDC 1997-_
Limited Partnership"), the deductibility of all or a portion of the IDC
may be deferred. Notwithstanding the foregoing, no assurance can be given
that the Service will not challenge the current deduction of IDC because
of the prepayment being made to a related party. If the Service were
successful with such challenge, the Partners' deductions for IDC would be
deferred to later years.
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C. Recapture of IDC
IDC previously deducted that is allocable to the property (directly or
through the ownership of an interest in a partnership) and which would
have been included in the adjusted basis of the property is recaptured to
the extent of any gain realized upon the disposition of the property.
Recently promulgated Treasury regulations provide that recapture is
determined at the partner level (subject to certain anti-abuse
provisions). Where only a portion of recapture property is disposed of,
any IDC related to the entire property is recaptured to the extent of the
gain realized on the portion of the property sold. In the case of the
disposition of an undivided interest in a property (as opposed to the
disposition of a portion of the property), a proportionate part of the IDC
with respect to the property is treated as allocable to the transferred
undivided interest to the extent of any realized gain.
Depletion Deductions
- Unless they are already substantially involved in the oil and gas
business, investors will be entitled to claim a percentage depletion
deduction on their oil and gas income currently equal to 15% of
gross revenue from the properties not to exceed 100% of the taxable
income (excluding depletion) from the property or 65% of the
taxpayer's taxable income (subject to certain adjustments).
The owner of an economic interest in an oil and gas property is
entitled to claim the greater of percentage depletion or cost depletion
with respect to oil and gas properties which qualify for such depletion
methods. In the case of partnerships, the depletion allowance must be
computed separately by each partner and not by the partnership. For
properties placed in service after 1986, depletion deductions, to the
extent they reduce basis in an oil and gas property, are subject to
recapture under section 1254.
Cost depletion for any year is determined by multiplying the number of
units (e.g., barrels of oil or Mcf of gas) sold during the year by a
fraction, the numerator of which is the cost or other basis of the mineral
interest and the denominator of which is total reserves available at the
beginning of the period. In no event can the cost depletion exceed the
adjusted basis of the property to which it relates.
Percentage depletion is a statutory allowance pursuant to which a
deduction currently equal to 15% of the taxpayer's gross income from each
property is allowed in any taxable year, not to exceed 100% of the
taxpayer's taxable income from the property (computed without the
allowance for depletion) with the aggregate deduction limited to 65% of
the taxpayer's taxable income for the year (computed without regard to
percentage depletion and net operating loss and capital loss carrybacks).
The percentage depletion deduction rate will vary with the price of oil,
but the rate will not be less than 15%. A percentage depletion deduction
that is disallowed in a year due to the 65% of taxable income limitation
may be carried forward and allowed as a deduction for the following year,
subject to the 65% limitation in that subsequent year. Percentage
depletion deductions reduce the taxpayer's adjusted basis in the property.
However, unlike cost depletion, deductions under percentage depletion are
not limited to the adjusted basis of the property; the percentage
depletion amount continues to be allowable as a deduction after the
adjusted basis has been reduced to zero.
The availability of depletion, whether cost or percentage, will be
determined separately by each Partner. Each Partner must separately keep
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records of his share of the adjusted basis in an oil or gas property,
adjust such share of the adjusted basis for any depletion taken on such
property, and use such adjusted basis each year in the computation of his
cost depletion or in the computation of his gain or loss on the
disposition of such property. These requirements may place an
administrative burden on a Partner.
Depreciation Deductions
The Partnership will claim depreciation, cost recovery, and
amortization deductions with respect to its basis in Partnership Property
as permitted by the Code. For most tangible personal property placed in
service after December 31, 1986, the "modified accelerated cost recovery
system" ("MACRS") must be used in calculating the cost recovery
deductions. Thus, the cost of lease equipment and well equipment, such as
casing, tubing, tanks, and pumping units, and the cost of oil or gas
pipelines cannot be deducted currently but must be capitalized and
recovered under MACRS. The cost recovery deduction for most equipment
used in domestic oil and gas exploration and production and for most of
the tangible personal property used in natural gas gathering systems is
calculated using the 200% declining balance method switching to the
straight-line method, a seven-year recovery period, and a half-year
convention. If an accelerated depreciation method is used, a portion of
the depreciation will be a preference item for AMT purposes.
Interest Deductions
In the Transaction, the Investor Partners will acquire their interests
by remitting cash in the amount of $20,000 per Unit to the Partnership.
In no event will the Partnership accept notes in exchange for a
Partnership interest. Nevertheless, without any assistance from the
Managing General Partner or any of its affiliates, some Partners may
choose to borrow the funds necessary to acquire a Unit and may incur
interest expense in connection with those loans. Based upon the purely
factual nature of any such loans, counsel is unable to express an opinion
with respect to the deductibility of any interest paid or incurred
thereon.
Transaction Fees
- Partnership expenditures classified as organizational expenses, and
start-up expenses may be amortized over periods ranging from 60
months to the life of the property.
- No deduction is permitted for syndication expenses, including sales
commissions for the purchase of Units.
The Partnership may classify a portion of the fees to be paid to third
parties and to the Managing General Partner or to the Operator and its
affiliates (as described in the Prospectus under "Source of Funds and Use
of Proceeds") as expenses which are deductible as organizational expenses
or otherwise. There is no assurance that the Service will allow the
deductibility of such expenses and counsel expresses no opinion with
respect to the allocation of the Fees to deductible and nondeductible
items.
Generally, expenditures made in connection with the creation of, and
with sales of interests in, a partnership will fit within one of several
categories.
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A partnership may elect to amortize and deduct its organizational
expenses ratably over a period of not less than 60 months commencing with
the month the partnership begins business. Examples of organizational
expenses are legal fees for services incident to the organization of the
partnership, such as negotiation and preparation of a partnership
agreement, accounting fees for services incident to the organization of
the partnership, and filing fees.
No deduction is allowable for "syndication expenses," examples of which
include brokerage fees, registration fees, legal fees of the underwriter
or placement agent and the issuer (general partners or the partnership)
for securities advice and for advice pertaining to the adequacy of tax
disclosures in the prospectus or private placement memorandum for
securities law purposes, printing costs, and other selling or promotional
material. These costs must be capitalized. Payments for services
performed in connection with the acquisition of capital assets must be
amortized over the useful life of such assets.
No deduction is allowable with respect to "start-up expenditures,"
although such expenditures may be capitalized and amortized over a period
of not less than 60 months.
The Partnership intends to make payments to the Managing General
Partner, as described in greater detail in the Prospectus. To be
deductible, compensation paid to a general partner must be for services
rendered by the partner other than in his capacity as a partner or for
compensation determined without regard to partnership income. Fees which
are not deductible because they fail to meet this test may be treated as
special allocations of income to the recipient partner and thereby
decrease the net loss, or increase the net income among all partners. If
the Service were to successfully challenge the Managing General Partner's
allocations, a Partner's taxable income could be increased, thereby
resulting in increased taxes and in liability for interest and penalties.
Basis and At Risk Limitations
- Partners contributing cash from 'personal funds' will not be
limited, to the extent of cash contributed, in their deductibility
of Partnership losses by the 'at risk' or 'adjusted basis' rules."
A Partner's share of Partnership losses will be allowed only to the
extent of the aggregate amount with respect to which the taxpayer is "at
risk" for such activity at the close of the taxable year. Any such loss
disallowed by the "at risk" limitation shall be treated as a deduction
allocable to the activity in the first succeeding taxable year.
The Code provides that a taxpayer must recognize taxable income to the
extent that his "at risk" amount is reduced below zero. This recaptured
income is limited to the sum of the loss deductions previously allowed to
the taxpayer, less any amounts previously recaptured. A taxpayer may be
allowed a deduction for the recaptured amounts included in his taxable
income if and when he increases his amount "at risk" in a subsequent
taxable year.
The Partners will purchase Units by tendering cash to the Partnership.
To the extent the cash contributed constitutes the "personal funds" of the
Partners, the Partners should be considered at risk with respect to those
amounts. To the extent the cash contributed constitutes "personal funds,"
in the opinion of counsel, neither at the risk rules nor the adjusted
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basis rules will limit the deductibility of losses generated from the
Partnership. In no event, however, may a partner utilize his distributive
share of partnership loss where such share exceeds the partner's basis in
the partnership.
Passive Loss Limitations
A. Introduction
The deductibility of losses generated from passive activities will be
limited for certain taxpayers. The passive activity loss limitations
apply to individuals, estates, trusts, and personal service corporations
as well as, to a lesser extent, closely held C corporations.
The definition of a "passive activity" generally encompasses all rental
activities as well as all activities with respect to which the taxpayer
does not "materially participate." Notwithstanding this general rule,
however, the term "passive activity" does not include "any working
interest in any oil or gas property which the taxpayer holds directly or
through an entity which does not limit the liability of the taxpayer with
respect to such interest." A taxpayer will be considered as materially
participating in a venture only if the taxpayer is involved in the
operations of the activity on a "regular, continuous, and substantial"
basis. In addition, no limited partnership interest will be treated as an
interest with respect to which a taxpayer materially participates.
A passive activity loss ("PAL") is the amount by which the aggregate
losses from all passive activities for the taxable year exceed the
aggregate income from all passive activities for such year.
Individuals and personal service corporations will be entitled to PALs
only to the extent of their passive income whereas closely held C
corporations (other than personal service corporations) can offset PALs
against both passive and net active income, but not against portfolio
income. In calculating passive income and loss, however, all activities
of the taxpayer are aggregated. PALs disallowed as a result of the above
rules will be suspended and can be carried forward indefinitely to offset
future passive (or passive and active, in the case of a closely held C
corporation) income.
Upon the disposition of an entire interest in a passive activity in a
fully taxable transaction not involving a related party, any passive loss
that was suspended by the provisions of the passive activity rules is
deductible from either passive or non-passive income. The deduction must
be reduced, however, by the amount of income or gain realized from the
activity in previous years.
B. General Partner Interests
- General Partner Interests will not be considered as investments in
passive activities for federal tax purposes.
- Additional General Partners who convert to limited partner status
after recording a tax loss from their investment in any year will
continue to have income treated as non-passive, but may have some or
all of their deductions treated as passive.
An Additional General Partner's interest in the Partnership will not be
considered a passive activity and losses generated while such general
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partner interest is held will not be limited by the passive activity
provisions, unless there is partnership income or losses from non-working
interests.
Notwithstanding this general rule, however, the economic performance
rules are applied in a different manner from that described above in
"Intangible Drilling and Development Costs Deductions." Economic
performance under the passive loss rules is defined as economic
performance, without regard to the spudding rule. Accordingly, if an
Additional General Partner's interest is converted to that of a limited
partner after the end of the year in which economic performance is deemed
to occur, but prior to the spudding date, any post-conversion losses will
be passive, notwithstanding the availability of such losses in a year in
which the taxpayer held the interest in an entity that did not limit his
liability. The "spudding rule" and "spudding date" refer to the date that
drilling commences.
If an Additional General Partner converts his interest to a Limited
Partner interest pursuant to the terms of the Partnership Agreement, the
character of a subsequently generated tax attribute will be dependent
upon, among other things, the nature of the tax attribute and whether
there arose, prior to conversion, losses to which the working interest
exception applied.
Accordingly, any loss arising therefrom should be treated as a PAL with
the benefits thereof limited as described above. However, if a taxpayer
has any loss from any taxable year from a working interest in any oil or
gas property that is treated as a non-passive loss, then any net income
from such property for any succeeding taxable year is to be treated as
income that is not from a passive activity. Consequently, assuming that
a converting Additional General Partner has losses from working interests
which are treated as non-passive, income from the Partnership allocable to
the Partner after conversion would be treated as income that is not from
a passive activity.
C. Limited Partner Interests
- Income and losses of Limited Partners will be treated as "passive"
for federal tax purposes.
If an Investor Partner invests in the Partnership as a Limited Partner,
his distributive share of the Partnership's losses will be treated as
PALs, the availability of which will be limited to the Partner's passive
income. If the Partner does not have sufficient passive income to utilize
the PAL, the disallowed PAL will be suspended and may be carried forward
to be deducted against passive income arising in future years. Further,
upon the disposition of the interest to an unrelated party, in a fully
taxable transaction such suspended losses will be available, as described
above.
Limited Partners should generally be entitled to offset their
distributive shares of passive income from the Partnerships with
deductions from other passive activities, but not portfolio income.
Conversion of Interests
The Partnership, in the opinion of counsel, will not be terminated
solely as a result of the conversion by Additional General Partners of
their Partnership interests into limited partnership interests. In the
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event a constructive termination does occur, however, there will be a
deemed distribution of the Partnership's assets to the Partners and a
recontribution by such Partners to the Partnership. This constructive
termination could have adverse Federal income tax consequences, described
in the opinion in Appendix D. For a discussion of the conversion feature
of the Program, see "Terms of the Offering -- Conversion of Units by
Additional General Partners."
Alternative Minimum Tax
- Due to the potentially significant impact of a purchase of Units on
an Investor's tax liability, investors should discuss the
implications of an investment in the Partnership on their regular
and AMT liabilities with their tax advisors prior to acquiring
Units.
Tax benefits associated with oil and gas exploration activities similar
to that of the Program had for several years been subject to the AMT.
Specifically, prior to January 1, 1993, intangible drilling cost ("IDC")
was an AMT preference item to the extent that "excess IDC" exceeded 65% of
a taxpayer's net income from oil and gas properties for the year. Excess
IDC was the amount by which the taxpayer's IDC deduction exceeded the
deduction that would have been allowed if the IDC had been capitalized and
amortized on a straight-line basis over ten years. Percentage depletion,
to the extent it exceeded a property's basis, was also an AMT preference
item.
For independent produces in taxable years beginning after 1992, the
Energy Policy Act repealed the treatment of percentage depletion as a
preference item for AMT purposes and reduced the AMT on expensing of IDC
by 30%.
For corporations, other than integrated oil companies, the adjusted
current earning ("ACE") adjustments were also repealed.
Gain or Loss on Sale of Property or Units
- Sale or exchange of property by the Partnership or a Unit by an
investor could result in taxable income in the year of the sale to
the investor in excess of the value of money and property received
from the sale.
- Investors who fail to report a sale or exchange of a Unit in the
Partnership could be subject to a penalty of 5% of the aggregate
income not reported.
In the event some or all of the property of the Partnership is sold, or
upon sale of a Unit (including a sale under the Unit Repurchase Program),
an investor will recognize gain to the extent the amount realized exceeds
his basis in the investment. In addition, there may be recapture of IDCs
and depletion which is treated as additional ordinary income for tax
purposes. If the gain exceeds the amount of the recaptured income, the
investor will recognize ordinary income to the extent of the recapture and
capital gains for the balance.
It is possible that an investor will be required to recognize ordinary
income pursuant to the recapture rules in excess of the taxable income of
the disposition transaction or in a situation where the disposition
transaction resulted in a taxable loss. To balance the excess income, the
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investor would recognize a capital loss for the difference between the
gain and the income. Depending on an investor's particular tax situation,
some or all of this loss might be deferred to future years, resulting in
a greater tax liability in the year in which the sale was made and a
reduced future tax liability.
Any partner who sells or exchanges interests in a partnership must
generally notify the partnership in writing within 30 days of such
transaction in accordance with Regulations and must attach a statement to
his tax return reflecting certain facts regarding the sale or exchange.
The notice must include names, addresses, and taxpayer identification
numbers (if known) of the transferor and transferee and the date of the
exchange. The partnership also is required to provide copies of the
information it provides to the Service to the transferor and the
transferee.
Any investor who is required to notify the Partnership of a transfer of
his Partnership interest, and, who fails to do so, may be fined $50 for
each failure, limited to $100,000, provided no intentional disregard of
the filing requirement. Similarly, the Partnership may be fined for
failure to report the transfer. The partnership's penalty is $50 for each
failure, limited to $250,000, provided no intentional disregard of the
filing requirement.
The tax consequences to an assignee purchaser of a Unit from a Partner
are not described herein. Any assignor of a Unit should advise his
assignee to consult his own tax advisor regarding the tax consequences of
such assignment.
Partnership Distributions
Under the Code, any increase in a partner's share of partnership
liabilities, or any increase in such partner's individual liabilities by
reason of an assumption by him of partnership liabilities is considered to
be a contribution of money by the partner to the partnership. Similarly,
any decrease in a partner's share of partnership liabilities or any
decrease in such partner's individual liabilities by reason of the
partnership's assumption of such individual liabilities will be considered
as a distribution of money to the partner by the partnership.
The Partners' adjusted bases in their Units will initially consist of
the cash they contribute to the Partnership. Their bases will be
increased by their share of Partnership income and additional
contributions and decreased by their share of Partnership losses and
distributions. To the extent that such actual or constructive
distributions are in excess of a Partner's adjusted basis in his
Partnership interest (after adjustment for contributions and his share of
income and losses of the Partnership), that excess will generally be
treated as gain from the sale of a capital asset. In addition, gain could
be recognized to a distributee partner upon the disproportionate
distribution to a partner of unrealized receivables or substantially
appreciated inventory. The Partnership Agreement prohibits distributions
to any Investor Partner to the extent such would create or increase a
deficit in the Partner's Capital Account.
Partnership Allocations
The Partners' distributive shares of partnership income, gain, loss,
and deduction should be determined and allocated substantially in
accordance with the terms of the Partnership Agreement.
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The Service could contend that the allocations contained in the
Partnership Agreement do not have substantial economic effect or are not
in accordance with the Partners' interests in the Partnership and may seek
to reallocate these items in a manner that will increase the income or
gain or decrease the deductions allocable to a Partner.
Profit Motive
- Investors who enter a business without economic, nontax profit
motive may be denied the benefits of deductions associated with the
business to the extent they exceed the income from the business.
The existence of economic, nontax motives for entering into the
Transaction is essential if the Partners are to obtain the tax benefits
associated with an investment in the Partnership.
Where an activity entered into by an individual is not engaged in for
profit, the individual's deductions with respect to that activity are
limited to those not dependent upon the nature of the activity (e.g.,
interest and taxes); any remaining deductions will be limited to gross
income from the activity for the year. Should it be determined that a
Partner's activities with respect to the Transaction are "not for profit,"
the Service could disallow all or a portion of the deductions generated by
the Partnership's activities.
The Code generally provides for a presumption that an activity is
entered into for profit where gross income from the activity exceeds the
deductions attributable to such activity for three or more of the five
consecutive taxable years ending with the taxable year in question. At
the taxpayer's election, such presumption can relate to three or more of
the taxable years in the 5-year period beginning with the taxable year in
which the taxpayer first engages in the activity.
Due to the inherently factual nature of a Partner's intent and motive
in engaging in the Transaction, counsel does not express an opinion as to
the ultimate resolution of this issue in the event of a challenge by the
Service. Partners must, however, seek to make a profit from their
activities with respect to the Transaction beyond any tax benefits derived
from those activities or risk losing those tax benefits.
Administrative Matters
Returns and Audits. While no federal income tax is required to be paid
by an organization classified as a partnership for federal income tax
purposes, a partnership must file federal income tax information returns,
which are subject to audit by the Service. Any such audit may lead to
adjustments, in which event the Investor Partners may be required to file
amended personal federal income tax returns. Any such audit may also lead
to an audit of an Investor Partner's individual tax return and adjustments
to items unrelated to an investment in units.
For purposes of reporting, audit, and assessment of additional federal
income tax, the tax treatment of "partnership items" is determined at the
partnership level. Partnership items will include those items that the
Regulations provide are more appropriately determined at the partnership
level than the partner level. The Service generally cannot initiate
deficiency proceedings against an individual partner with respect to
partnership items without first conducting an administrative proceeding at
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the partnership level as to the correctness of the partnership's treatment
of the item. An individual partner may not file suit for a credit or a
refund arising out of a partnership item without first filing a request
for an administrative proceeding by the Service at the partnership level.
Individual partners are entitled to notice of such administrative
proceedings and decisions therein, except in the case of partners with
less than 1% profits interest in a partnership having more than 100
partners. If a group of partners having an aggregate profits interest of
5% or more in such a partnership so requests, however, the Service also
must mail notice to a partner appointed by that group to receive notice.
All partners, whether or not entitled to notice, are entitled to
participate in the administrative proceedings at the partnership level,
although the Partnership Agreement provides for waiver of certain of these
rights by the Investor Partners. All Investor Partners, including those
not entitled to notice, may be bound by a settlement reached by the
Partnership's representative "tax matters partner", which will be
Petroleum Development Corporation. If a proposed tax deficiency is
contested in any court by any Partner of a Partnership or by the Managing
General Partner, all Partners of that Partnership may be deemed parties to
such litigation and bound by the result reached therein.
Consistency Requirements. An Investor Partner must generally treat
Partnership items on his federal income tax returns consistently with the
treatment of such items on the Partnership information return unless he
files a statement with the Service identifying the inconsistency or
otherwise satisfies the requirements for waiver of the consistency
requirement. Failure to satisfy this requirement will result in an
adjustment to conform the Investor Partner's treatment of the item with
the treatment of the item on the Partnership return. Intentional or
negligent disregard of the consistency requirement may subject an Investor
Partner to substantial penalties.
Compliance Provisions. Taxpayers are subject to several penalties and
other provisions that encourage compliance with the federal income tax
laws, including an accuracy-related penalty in an amount equal to 20% of
the portion of an underpayment of tax caused by negligence, intentional
disregard of rules or regulations or any "substantial understatement" of
income tax. A "substantial understatement" of tax is an understatement of
income tax that exceeds the greater of (a) 10% of the tax required to be
shown on the return (the correct tax), or (b) $5,000 ($10,000 in the case
of a corporation other than an S corporation or personal holding
corporation).
Except in the case of understatements attributable to "tax shelter"
items, an item of understatement may not give rise to the penalty if (a)
there is or was "substantial authority" for the taxpayer's treatment of
the item or (b) all facts relevant to the tax treatment of the item are
disclosed on the return or on a statement attached to the return, and
there is a reasonable basis for the tax treatment of such item by the
taxpayer. In the case of partnerships, the disclosure is to be made on
the return of the partnership. Under the applicable Regulations, however,
an individual partner may make adequate disclosure with respect to
partnership items if certain conditions are met.
In the case of understatements attributable to "tax shelter" items, the
substantial understatement penalty may be avoided only if the taxpayer
establishes that, in addition to having substantial authority for his
position, he reasonably believed the treatment claimed was more likely
than not the proper treatment of the item. A "tax shelter" item is one
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that arises from a partnership (or other form of investment) the principal
purpose of which is the avoidance or evasion of federal income tax. Under
the GATT legislation, a corporation is generally held to a higher standard
to avoid the substantial understatement penalty.
Based on the definition of a "tax shelter" in the Regulations,
performance of previous partnerships, and the planned activities of the
Program, the Managing General Partner does not believe that the
Partnerships will qualify as "Tax Shelters" under the Code, and will not
register them as such.
Accounting Methods and Periods
The Partnership will use the accrual method of accounting and will
select the calendar year as its taxable year.
Social Security Benefits; Self-employment Tax
A General Partner's share of any income or loss attributable to Units
will constitute "net earnings from self-employment" for both social
security and self-employment tax purposes, while a Limited Partner's share
of such items will not constitute "net earnings from self-employment."
Thus, no quarters of coverage or increased benefits under the Social
Security Act will be earned by Limited Partners. If a General Partner is
receiving Social Security benefits, his taxable income attributable to his
investment in the Units must be taken into account in determining any
reduction in benefits because of "excess earnings."
State and Local Taxes
The opinions expressed herein are limited to issues of federal income
tax law and do not address issues of state or local law. Investors are
urged to consult their tax advisors regarding the impact of state and
local laws on an investment in the Partnership.
Individual Tax Advice Should Be Sought
The foregoing is only a summary of the material tax considerations that
may affect an investor's decision regarding the purchase of Units. The
tax considerations attendant to an investment in a Partnership are
complex, vary with individual circumstances, and depend in some instances
upon whether the investor acquires General Partner Interests or Limited
Partner Interests. Each prospective Investor Partner should review such
tax consequences with his tax advisor.
SUMMARY OF PARTNERSHIP AGREEMENT
The rights and obligations of the Partners will be governed by the
Limited Partnership Agreement (the "Partnership Agreement") in the form
attached to this Prospectus as Appendix A. Each prospective investor,
together with his personal advisers, should carefully study the
Partnership Agreement in its entirety before submitting a subscription.
The following statements concerning the Partnership Agreement are merely
an outline, do not purport to be complete and in no way amend or modify
the Partnership Agreement.
Responsibility of Managing General Partner
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The Managing General Partner shall have the exclusive management and
control of all aspects of the business of the Partnership. Sections 5.01
and 6.01 of the Partnership Agreement. No Investor Partner shall have any
voice in the day-to-day business operations of the Partnership. Section
7.01. The Managing General Partner is authorized to delegate and
subcontract its duties under the Partnership Agreement to others,
including entities related to it. Section 5.02.
Liabilities of General Partners, Including Additional General Partners
General Partners, including Additional General Partners, will not be
protected by limited liability for Partnership activities. The Additional
General Partners will be jointly and severally liable for all obligations
and liabilities to creditors and claimants, whether arising out of
contract or tort, in the conduct of Partnership operations. Section 7.12.
The Managing General Partner, as Operator, maintains general liability
insurance. In addition, the Managing General Partner has agreed to
indemnify each of the Additional General Partners for obligations related
to casualty and business losses which exceed available insurance coverage
and Partnership assets. Section 7.02.
The Additional General Partners, by execution of the Partnership
Agreement, grant to the Managing General Partner the exclusive authority
to manage the Partnership business in its sole discretion and to thereby
bind the Partnership and all Partners in its conduct of the Partnership
business. The Additional General Partners will not be authorized to
participate in the management of the Partnership business; and the
Partnership Agreement prohibits the Additional General Partners from
acting in a manner harmful to the assets or the business of the
Partnership or to do any other act which would make it impossible to carry
on the ordinary business of the Partnership. If an Additional General
Partner acts in contravention of the terms of the Partnership Agreement,
losses caused by his actions will be borne by such Additional General
Partner alone and such Additional General Partner may be liable to other
Partners for all damages resulting from his breach of the Partnership
Agreement. Section 7.01. Additional General Partners who choose to
assign their Units in the future may only do so as provided in the
Partnership Agreement and liability of Partners who have assigned their
Units may continue after such assignment unless a formal assumption and
release of liability is effected. Section 7.03.
Liability of Limited Partners
The Partnerships will be governed by the West Virginia Uniform Limited
Partnership Act under which a Limited Partner's liability for the
obligations of the partnership is limited to his Capital Contribution, his
share of Partnership assets and the return of any part of his Capital
Contribution for a period of one year after such return (or six years in
the event such return is in violation of the Agreement). A Limited
Partner will not otherwise be liable for the obligations of the
Partnership unless, in addition to the exercise of his rights and powers
as a Limited Partner, such person takes part in the control of the
business of the Partnership. Section 7.01.
Allocations and Distributions
General: Profits and losses are to be allocated and cash is to be
distributed in the manner described in the section entitled "Participation
in Costs and Revenues." See Article III of the Partnership Agreement.
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Time of Distributions: Cash available for distribution will be
determined and distributed by the Managing General Partner not less
frequently than quarterly. Section 4.01. The Managing General Partner
may, at its discretion, make distributions more frequently.
Notwithstanding any other provision of the Partnership Agreement to the
contrary, no Partner will receive any distribution to the extent such
distribution will create or increase a deficit in that Partner's Capital
Account (as increased by his share of Partnership Minimum Gain). Section
4.03.
Liquidating Distributions: Liquidating distributions will be made in
the same manner as regular distributions; however, in the event of
dissolution of the Partnership, distributions will be made only after due
provision has been made for, among other things, payment of all
Partnership debts and liabilities. Section 9.03.
Voting Rights
Investor Partners owning 10% or more of the then outstanding Units
entitled to vote have the right to require the Managing General Partner to
call a meeting of the Partners. Section 7.07.
Investor Partners will be entitled to vote with respect to Partnership
matters. Each Unit is entitled to one vote on all matters; each
fractional Unit is entitled to that fraction of one vote equal to the
fractional interest in the Unit. Except as otherwise provided herein or
in the Partnership Agreement, at any meeting of Investor Partners, a vote
of a majority of Units represented at such meeting, in person or by proxy,
with respect to matters considered at the meeting at which a quorum is
present will be required for approval of any such matters. A vote of a
majority of the then outstanding Units entitled to vote will be required
to approve any of the following matters:
(a) The sale of all or substantially all of the assets of the
Partnership;
(b) Removal of the Managing General Partner and election of a new
managing general partner;
(c) Dissolution of the Partnership;
(d) Any non-ministerial amendment to the Partnership Agreement;
(e) Cancellation of contracts for services with the Managing General
Partner or Affiliates; and
(f) The appointment of a liquidating trustee in the event the
Partnership is to be dissolved by reason of the retirement,
dissolution, liquidation, bankruptcy, death, or adjudication
of insanity or incapacity of the last remaining General Partner.
Additionally, the Partnership is not permitted to participate in a
Roll-Up transaction unless the Roll-Up has been approved by at least 66
2/3% in interest of Investor Partners. Sections 5.07(m) and 7.08. In the
event that the Managing General Partner and/or its Affiliates purchase
Units in a Partnership, the Managing General Partner and/or Affiliate will
not be entitled to vote the Units so purchased. Section 6.03. The
Managing General Partner if it were removed by the Investor Partners may
elect to retain its interest in the Partnership as a Limited Partner in
the
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successor limited partnership (assuming that the Investor Partners
determined to continue the Partnership and elected a successor managing
general partner), in which case the former Managing General Partner would
be entitled to vote its interest as a Limited Partner. Section 7.06.
Investor Partners have the right to review the Partnership's books and
records and list of Investor Partners at any reasonable time and have a
copy of the list of Investor Partners mailed to the requesting Investor
Partner at the latter's expense. Investor Partners have the right to
submit proposals to the Managing General Partner for inclusion in the
voting materials for the next meeting of Investor Partners for
consideration and approval by the Investor Partners. With respect to the
merger or consolidation of the Partnership or the sale of all or
substantially all of the Partnership's assets, Investor Partners have the
right to exercise dissenter's rights for fair appraisal of their Units in
accordance with Section 31-1-123 of the West Virginia Corporation Law.
Sections 7.07, 7.08, and 8.01.
Retirement and Removal of the Managing General Partner
In the event that the Managing General Partner desires to withdraw from
the Partnership for whatever reason, it may do so only upon one hundred
twenty (120) days prior written notice and with the written consent of the
Investor Partners owning a majority of the then outstanding Units.
Section 6.03.
In the event that the Investor Partners desire to remove the Managing
General Partner, they may do so at any time upon ninety (90) days written
notice, with the consent of the Investor Partners owning a majority of the
then outstanding Units, and upon the selection of a successor managing
general partner, within such ninety-day period, by the Investor Partners
owning a majority of the then outstanding Units. Section 7.06.
Term and Dissolution
The Partnership will continue for a maximum period ending December 31,
2046 unless earlier dissolved upon the occurrence of any of the following:
(a) the written consent of the Investor Partners owning a majority
of the then outstanding Units;
(b) the retirement, bankruptcy, adjudication of insanity or
incapacity, withdrawal, removal, or death (or, in the case of a corporate
managing general partner, the retirement, withdrawal, removal,
dissolution, liquidation, or bankruptcy) of a managing general partner,
unless a successor managing general partner is selected by the Partners
pursuant to the Partnership Agreement or the remaining managing general
partner, if any, continues the Partnership's business;
(c) the sale, forfeiture, or abandonment of all or substantially all
of the Partnership's property; or
(d) the occurrence of any event causing dissolution of the
Partnership under the laws of the State of West Virginia.
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Section 9.01.
Indemnification
The Managing General Partner has agreed to indemnify each of the
Additional General Partners for obligations related to casualty losses
which exceed available insurance coverage and Partnership assets. Section
7.02.
If obligations incurred by the Partnership are the result of the
negligence or misconduct of an Additional General Partner, or the
contravention of the terms of the Partnership Agreement by the Additional
General Partner, then the foregoing indemnification by the Managing
General Partner will be unenforceable as to such Additional General
Partner and such Additional General Partner will be liable to all other
Partners for damages and obligations resulting therefrom. Section 7.02.
The Managing General Partner will be entitled to reimbursement and
indemnification for all expenditures made (including amounts paid in
settlement of claims) or losses or judgments suffered by it in the
ordinary and proper course of the Partnership's business, provided that
the Managing General Partner has determined in good faith that the course
of conduct which caused the loss or liability was in the best interests of
the Partnership, that the Managing General Partner was acting on behalf of
or performing services for the Partnership, and that such expenditures,
losses or judgments were not the result of the negligence or misconduct on
the part of the Managing General Partner. Section 6.04. The Managing
General Partner will have no liability to the Partnership or to any
Partner for any loss suffered by the Partnership which arises out of any
action or inaction of the Managing General Partner if the Managing General
Partner, in good faith, determined that such course of conduct was in the
best interest of the Partnership and such course of conduct did not
constitute negligence or misconduct of the Managing General Partner. The
Managing General Partner will be indemnified by the Partnership to the
limit of the insurance proceeds and tangible net assets of the Partnership
against any losses, judgments, liabilities, expenses and amounts paid in
settlement of any claims sustained by it in connection with the
Partnership, provided that the same were not the result of negligence or
misconduct on the part of the Managing General Partner.
Notwithstanding the above, the Managing General Partner will not be
indemnified for liabilities arising under Federal and state securities
laws unless (1) there has been a successful adjudication on the merits of
each count involving securities law violations; or (2) such claims have
been dismissed with prejudice on their merits by a court of competent
jurisdiction; or (3) a court of competent jurisdiction approves a
settlement of such claims against a particular indemnitee and finds that
indemnification of the settlement and the related costs should be made,
and the court considering the request for indemnification has been advised
of the position of the Securities and Exchange Commission and of the
position of any state securities regulatory authority in which securities
of the Partnership were offered or sold as to indemnification for
violations of securities laws; provided, however, the court need only be
advised of the positions of the securities regulatory authorities of those
states (i) which are specifically set forth in the Prospectus and (ii) in
which plaintiffs claim they were offered or sold Partnership Units.
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In any claim for indemnification for Federal or state securities laws
violations, the party seeking indemnification must place before the court
the position of the Securities and Exchange Commission and the
Massachusetts Securities Division, and the Tennessee Securities Division or
other respective state securities division with respect to the issue of
indemnification for securities laws violations.
The Partnership will not incur the cost of the portion of any insurance
which insures any party against any liability as to which such party is
herein prohibited from being indemnified. Section 6.04.
Reports to Partners
The Managing General Partner will furnish to the Investor Partners of
each Partnership certain semi-annual and annual reports which will contain
financial statements (including a balance sheet and statements of income,
Partners' equity and cash flows), which statements at fiscal year end will
be audited by an independent accounting firm and will include a
reconciliation of such statements with information provided to the
Investor Partners for Federal income tax purposes. Financial statements
furnished in a Partnership's semi-annual reports will not be audited.
Semi-annually, all Investor Partners will also receive a summary
itemization of the transactions between the Managing General Partner or
any Affiliate thereof and the Partnership showing all items of
compensation received by the Managing General Partner and its Affiliates.
Annually beginning with the fiscal year ended December 31, 1996 with
respect to Partnerships designated "PDC 1996-_ Limited Partnership" and
December 31, 1997 with respect to Partnerships designated "PDC 1997-_
Limited Partnership," oil and gas reserve estimates prepared by an
independent petroleum engineer will also be furnished to the Investor
Partners. Annual reports will be provided to the Investor Partners within
120 days after the close of each Partnership fiscal year, and semi-annual
reports will be provided within 75 days after the close of the first six
months of each Partnership fiscal year. In addition, the Investor
Partners will receive on a monthly basis while the Partnership is
participating in the drilling and completion activities of a Program,
reports containing a description of the Partnership's acquisition of
interests in Prospects, including farmins and farmouts, and the drilling,
completion and abandonment of wells thereon. All Investor Partners will
receive a report containing information necessary for the preparation of
their Federal income tax returns and any required state income tax returns
by March 15 of each calendar year. Investor Partners will also receive in
such monthly reports a summary of the status of wells drilled by the
Partnership, the amount of oil or gas from each well and the drilling
schedule for proposed wells, if known. The Managing General Partner may
provide such other reports and financial statements as it deems necessary
or desirable. Section 8.02.
Power of Attorney
Each Partner will grant to the Managing General Partner a power of
attorney to execute certain documents deemed by the Managing General
Partner to be necessary or convenient to the Partnership's business or
required in connection with the qualification and continuance of the
Partnership. Section 10.01.
Other Provisions
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Other provisions of the Partnership Agreement are summarized in this
Prospectus under the headings "Terms of the Offering," "Source of Funds
and Use of Proceeds," "Participation in Costs and Revenues," "Management,"
"Fiduciary Responsibility of the Managing General Partner," and
"Transferability of Units." The attention of prospective investors is
directed to these sections.
TRANSFERABILITY OF UNITS
- The sale of Units by investors is limited; no market for the Units
will develop.
- Purchasers of Units from investors must satisfy the suitability
requirements of this offering and as imposed by law.
No market for the Units will develop. An investment in the
Partnerships should be considered an illiquid investment. Investors may
not be able to sell their Units. In addition, as a basis of counsel's
opinion that the Partnerships will not be treated as "publicly traded
partnerships," the Managing General Partner has represented that the Units
will not be traded on an established securities market or the substantial
equivalent thereof.
While Units of the Partnership are transferable, assignability of the
Units is limited, requiring among other things the consent of the Managing
General Partner. Section 7.03. Transfers of fractional Units are
prohibited, unless the Investor Partner owns less than a whole Unit, in
which case his entire fractional interest must be transferred. Units may
be assigned only to a person otherwise qualified to become an Investor
Partner, including the satisfaction of any relevant suitability
requirements, as imposed by law or the Partnership. In no event may any
assignment be made which, in the opinion of counsel to the Partnership,
would result in the Partnership being considered to have been terminated
for purposes of Section 708 of the Code, unless the Managing General
Partner consents to such an assignment, or which, in the opinion of
counsel to the Partnership, would result in the Partnership being treated
as a publicly traded partnership, or which, in the opinion of counsel to
the Partnership, may not be effected without registration under the
Securities Act of 1933, as amended, or would result in the violation of
any applicable state securities laws. A substituted Additional General
Partner will have the same rights and responsibilities, including
unlimited liability, in the Partnership as every other Additional General
Partner. Upon receipt of notice of a purported transfer or assignment of
a Unit of general partnership interest, the Managing General Partner,
after having determined that the purported transferee satisfies the
suitability standards of an Additional General Partner and other
conditions established by the Program, will promptly notify the purported
transferee of the Partnership's consent to the transfer and will include
with the notice a copy of the Partnership Agreement, together with a
signature page. In such notification, the Managing General Partner will
advise the transferee that he will have the same rights and
responsibilities, including unlimited liability, as every other Additional
General Partner and that he will not become a Partner of record until he
returns the executed signature page to the Partnership. A Partnership
will not be required to recognize any assignment until the instrument of
assignment has been delivered to the Managing General Partner. The
assignee of such interests has certain rights of ownership but may become
a substituted Investor Partner and thus be entitled to all of the rights
of an Additional General Partner or Limited Partner only upon meeting
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certain conditions, including (i) obtaining the consent of the Managing
General Partner to such substitution, (ii) paying all costs and expenses
incurred in connection with such substitution, (iii) making certain
representations to the Managing General Partner and (iv) executing
appropriate documents to evidence its agreement to be bound by all of the
terms and provisions of the applicable Partnership Agreement.
Conversion of Units by Additional General Partners. Upon written
notice to the Managing General Partner, Additional General Partners will
have the right to convert their interests into limited partnership
interests and thereafter become Limited Partners of the Partnership. See
"Terms of the Offering -- Conversion of Units by Additional General
Partners." Moreover, upon completion of drilling of a particular
Partnership, the Managing General Partner will convert all Units of
general partnership interest of that Partnership into Units of limited
partnership interest of that Partnership.
Unit Repurchase Program. Beginning with the third anniversary of the
date of the first cash distribution of the Partnership, Partners may
tender their Units to the Managing General Partner for repurchase, subject
to certain conditions. See "Terms of the Offering -- Unit Repurchase
Program."
PLAN OF DISTRIBUTION
- An affiliate of the Managing General Partner is dealer manager of
the offering.
- Sales will be made on a "minimum-maximum best efforts" basis through
NASD-licensed broker-dealers.
- Broker-dealers will receive an amount equal to 10 1/2% of the
subscription proceeds as sales commissions, expenses, and
wholesaling fees.
- Purchase of Units by the Managing General Partner and/or Affiliates
may allow the offering to satisfy the minimum sales requirements and
thereby allow the offering to close and a partnership to be funded.
Units of preformation limited and general partnership interest are
being offered for sale through PDC Securities Incorporated, the Dealer
Manager, an Affiliate of the Managing General Partner, as principal
distributor, and through NASD-licensed broker-dealers on a "minimum-
maximum best efforts" basis for each Partnership, to a select group of
investors who meet the suitability standards set forth under "Terms of the
Offering -- Investor Suitability." Units will not be sold to tax-exempt
investors or to foreign investors. "Minimum-maximum best efforts" means
(1) that the various broker-dealers which will sell the Units (a) will not
be obligated to sell or to purchase any amount of Units but (b) will be
obligated to make a reasonable and diligent effort (that is, their "best
efforts") to sell as many Units as possible and (2) that the offering will
not close unless the minimum number of Units (50 Units aggregating $1
million) is sold within the offering period. The term "maximum" refers to
the maximum proceeds ($10 million) that can be raised with respect to any
Partnership.
The Dealer Manager, an NASD member, will receive a sales commission
equal to 8% of the Investor Partners' Subscriptions and reimbursement of
due diligence expenses, marketing support fees, and other compensation
equal to 2% of the Investor Partners' Subscriptions, and wholesaling fees
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equal to 0.5% of the Investor Partners' Subscriptions, for an aggregate of
$5,250,000 ($105,000 if the minimum number of 50 Units is sold), which the
Dealer Manager may reallow, in whole or in part, to NASD-licensed broker-
dealers for sale of the Units. The Dealer Manager will not reallow the
wholesaling fees. In no event will the total compensation paid to NASD
members exceed 10% of Subscriptions (compromised of 8% in sales commissions,
0.5% in wholesaling fees, and 1.5% in marketing support fees and other
compensation) and 0.5% of Subscriptions for reimbursement of bona fide due
diligence expenses. In no event will such fees exceed in the aggregate 10
1/2% of the total Investor Partners' Subscriptions. Any such commissions
and other remuneration will be paid in cash solely on the amount of
initial Subscriptions and only as permitted under Federal and state
securities laws and applicable rules and regulations. As provided in the
soliciting dealers agreements between PDC Securities Incorporated and the
various soliciting dealers, the Managing General Partner, prior to the
time that $1 million or more of subscription funds have been received and
cleared from subscribers that the Managing General Partner deems suitable
to be Investor Partners in the Partnership in which Units are then being
offered, may advance to the various NASD-licensed broker-dealers from the
Managing General Partner's own funds the sales commissions and due
diligence expenses which would otherwise be payable in connection with
subscription funds received and cleared from subscribers that the Managing
General Partner deems suitable to be Investor Partners prior to the close
and funding of the Partnership. In the event that the minimum sale of 50
Units has not occurred as of such time as the particular offering
terminates or the Managing General Partner determines not to organize and
fund the Partnership for any reason, such broker-dealers which have been
advanced commissions and due diligence expenses by the Managing General
Partner with respect to the sale of Units in that Partnership are required
by the soliciting-dealers agreements to return such commissions and due
diligence expenses to the Managing General Partner promptly.
No sales commissions will be paid on sales of Units to officers,
directors, employees, or registered representatives of a Soliciting Dealer
if such Soliciting Dealer, in its discretion, has elected to waive such
sales commissions. Any Units so purchased will be held for investment and
not for resale.
The Managing General Partner, the Dealer Manager, and soliciting
dealers have agreed to indemnify one another against certain civil
liabilities, including liability under the Securities Act of 1933, as
amended. Members of the selling group may be deemed to be "underwriters"
as defined under the Securities Act of 1933, as amended, and their
commissions and other payments may be deemed to be underwriting
compensation.
The Dealer Manager may offer the Units and receive commissions in
connection with the sale of Units only in those states in which it is
lawfully qualified to do so.
The Managing General Partner and its Affiliates may elect to purchase
Units in the offering on the same terms and conditions as other investors,
net of commissions. The purchase of Units by the Managing General Partner
and/or its Affiliates may have the effect of allowing the offering to be
subscribed to the minimum, thereby satisfying an express condition of the
offering, and thus allow the offering to close. The Managing General
Partner and/or its Affiliates will not purchase more than 10% of the Units
subscribed by the Investor Partners in any Partnership. Additionally, not
more than $50,000 of Units purchased by the Managing General Partner and
Affiliates are permitted to be applied to satisfying the $1 million
minimum requirement. Any Units purchased by the Managing General Partner
and/or its Affiliates will be held for investment and not for resale.
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<PAGE>
SALES LITERATURE
In connection with the offering, the NASD-registered broker-dealers may
utilize various sales literature which discusses certain aspects of the
Program, namely, a Program highlight information piece which will
constitute the Prospectus summary ("Program Summary" in bullet format), an
introduction to the Program ("Flip Chart/Slide Presentation"), and
prospect letters ("Broker-Dealer Guide"). The Program may also utilize a
Program general summary piece ("Program Summary" in text format) and a
sheet presenting information regarding comparative investment deductions
("Investment Deductions"). Such sales material will not contain any
material information which is not also set forth in the Prospectus. The
offering of Units will be made only by means of this Prospectus.
LEGAL OPINIONS
The validity of the Units offered hereby and certain Federal income tax
matters discussed under "Tax Considerations" and in the tax opinion set
forth in Appendix D to the Prospectus have been passed upon by Metzger,
Hollis, Gordon & Mortimer, 1275 K Street, N.W., Washington, D.C. 20005.
EXPERTS
The Partnership reserve and future net revenues information which has
been presented under "Prior Activities -- Partnership Proved Reserves and
Future Net Revenues" has been prepared by Wright & Company, Inc.,
Brentwood, Tennessee, independent petroleum consultants.
The consolidated balance sheets of Petroleum Development Corporation
and subsidiaries as of December 31, 1994 and December 31, 1993 included
herein and in the Registration Statement have been included herein and in
the Registration Statement in reliance upon the reports of KPMG Peat
Marwick LLP, independent certified public accountants, appearing elsewhere
herein, and upon the authority of said firm as experts in accounting and
auditing.
ADDITIONAL INFORMATION
A Registration Statement on Form S-1 (Reg. No. 33-) with respect to the
Units offered hereby has been filed on behalf of the Partnerships with the
Securities and Exchange Commission, Washington, D.C. 20549, under the
Securities Act of 1933, as amended. This Prospectus does not contain all
of the information set forth in the Registration Statement, certain
portions of which have been omitted pursuant to the rules and regulations
of the Securities and Exchange Commission. Reference is made to such
Registration Statement, including exhibits, for further information.
Reference is hereby made to the copy of documents filed as exhibits to the
Registration Statement for full statements of the provisions thereof, and
each such statement in this Prospectus is qualified in all respects by
this reference. Copies of any materials filed as a part of the
Registration Statement may be obtained from the Securities and Exchange
Commission by payment of the requisite fees therefor or may be examined in
the offices of the Commission without charge. The delivery of this
Prospectus at any time does not imply that the information contained
herein is correct as of any time subsequent to the date hereof.
GLOSSARY OF TERMS
The following terms used in this Prospectus shall (unless the context
otherwise requires) have the following respective meanings:
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<PAGE>
Act: The West Virginia Uniform Limited Partnership Act.
Additional General Partners: Those Investor Partners who purchase Units
as additional general partners, and their transferees and assigns.
Administrative Costs: All customary and routine expenses incurred by the
Managing General Partner for the conduct of program administration,
including legal, finance, accounting, secretarial, travel, office rent,
telephone, data processing and other items of a similar nature.
Affiliate: An affiliate of a specified person means (a) any person
directly or indirectly owning, controlling, or holding with power to vote
10 percent or more of the outstanding voting securities of such specified
person; (b) any person 10 percent or more of whose outstanding voting
securities are directly or indirectly owned, controlled, or held with
power to vote, by such specified person; (c) any person directly or
indirectly controlling, controlled by, or under common control with such
specified person; (d) any officer, director, trustee or partner of such
specified person; and (e) if such specified person is an officer,
director, trustee or partner, any person for which such person acts in any
such capacity.
Assessment: Additional amounts of capital which may be mandatorily
required of or paid voluntarily by an Investor Partner beyond his
Subscription commitment.
Benson Formation: A late Devonian Age rock unit generally found 4,000 to
4,500 feet below the surface in the prospect area.
Capital Accounts: The accounts to be maintained for each Partner on the
books and records of the Partnership pursuant to Section 3.01 of the
Partnership Agreement.
Capital Contribution: With respect to each Investor Partner, the total
investment, including the original investment, assessments and amounts
reinvested, by such Investor Partner to the capital of the Partnership
pursuant to Section 2.02 of the Partnership Agreement and, with respect to
the Managing General Partner and Initial Limited Partner, the total
investment, including the original investment, assessments and amounts
reinvested, to the capital of the Partnership pursuant to Section 2.01 of
the Partnership Agreement.
Capital Expenditures: Those costs associated with property acquisition
and the drilling and completion of oil and gas wells which are generally
accepted as capital expenditures pursuant to the provisions of the
Internal Revenue Code.
Carried Interest: An equity interest in a program issued to a person
without consideration, in the form of cash or tangible property, in an
amount proportionately equivalent to that received from the participants.
Code: The Internal Revenue Code of 1986, as amended.
Cost: When used with respect to the sale of property to the Partnership,
means (a) the sum of the prices paid by the seller to an unaffiliated
person for such property, including bonuses; (b) title insurance or
examination costs, brokers' commissions, filing fees, recording costs,
transfer taxes, if any, and like charges in connection with the
acquisition of such property; (c) a pro rata portion of the seller's
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<PAGE>
actual necessary and reasonable expenses for seismic and geophysical
services; and (d) rentals and ad valorem taxes paid by the seller with
respect to such property to the date of its transfer to the buyer,
interest and points actually incurred on funds used to acquire or maintain
such property, and such portion of the seller's reasonable, necessary and
actual expenses for geological, engineering, drafting, accounting, legal
and other like services allocated to the property cost in conformity with
generally accepted accounting principles and industry standards, except
for expenses in connection with the past drilling of wells which are not
producers of sufficient quantities of oil or gas to make commercially
reasonable their continued operations, and provided that the expenses
enumerated in this subsection (d) hereof shall have been incurred not more
than 36 months prior to the purchase by the Partnership; provided that
such period may be extended, at the discretion of the state securities
administrator, upon proper justification. When used with respect to
services, "cost" means the reasonable, necessary and actual expense
incurred by the seller on behalf of the Partnership in providing such
services, determined in accordance with generally accepted accounting
principles. As used elsewhere, "cost" means the price paid by the seller
in an arm's-length transaction.
Dealer Manager: PDC Securities Incorporated, an affiliate of the Managing
General Partner.
Development Well: A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
Devonian Shale: Shales deposited during the Paleozoic Devonian Period as
defined in Section 272.103(e) of the Natural Gas Policy Act of 1978.
Direct Costs: All actual and necessary costs directly incurred for the
benefit of the Partnership and generally attributable to the goods and
services provided to the Partnership by parties other than the Managing
Limited Partner or its affiliates. Direct costs shall not include any
cost otherwise classified as organization and offering expenses,
administrative costs, operating costs or property costs. Direct costs may
include the cost of services provided by the Managing General Partner or
its affiliates if such services are provided pursuant to written contracts
and in compliance with Section 5.07(e) of the Partnership Agreement.
Distributable Cash: Cash remaining for distribution to the Managing
General Partner and the Investor Partners after the payment of all
Partnership obligations, including debt service and the establishment of
contingency reserves for anticipated future costs as determined by the
Managing General Partner.
Drilling and Completion Costs: All costs, excluding Operating Costs, of
drilling, completing, testing, equipping and bringing a well into
production or plugging and abandoning it, including all labor and other
construction and installation costs incident thereto, location and surface
damages, cementing, drilling mud and chemicals, drillstem tests and core
analysis, engineering and well site geological expenses, electric logs,
costs of plugging back, deepening, rework operations, repairing or
performing remedial work of any type, costs of plugging and abandoning any
well participated in by the Partnership, and reimbursements and
compensation to well operators, including charges paid to the Managing
General Partner as unit operator during the drilling and completion phase
of a well, plus the cost of the gathering systems and of acquiring
leasehold interests.
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<PAGE>
Dry Hole: Any well abandoned without having produced oil or gas in
commercial quantities.
Escrow Agent: PNC Bank, N.A., Pittsburgh, Pennsylvania, or its successor.
Exploratory Well: A well drilled to find commercially productive
hydrocarbons in an unproved area, to find a new commercially productive
horizon in a field previously found to be productive of hydrocarbons at
another horizon, or to significantly extend a known prospect.
Farmout: An agreement whereby the owner of a leasehold or Working
Interest agrees to assign an interest in certain specific acreage to the
assignees, retaining an interest such as an Overriding Royalty Interest,
an oil and gas payment, offset acreage or other type of interest, subject
to the drilling of one or more specific wells or other performance as a
condition of the assignment.
Horizon: A zone of a particular formation; that part of a formation of
sufficient porosity and permeability to form a petroleum reservoir.
IDC: Intangible drilling and development costs.
Independent Expert: A person with no material relationship to the
Managing General Partner who is qualified and who is in the business of
rendering opinions regarding the value of oil and gas properties based
upon the evaluation of all pertinent economic, financial, geologic and
engineering information available to the Managing General Partner.
Initial Limited Partner: Steven R. Williams or any successor to his
interest.
Investor Partner: Any investor participating in the Partnership as an
Additional General Partner or a Limited Partner, but excluding the
Managing General Partner and Initial Limited Partner.
Landowners' Royalty Interest: An interest in production, or the proceeds
therefrom, to be received free and clear of all costs of development,
operation, or maintenance, reserved by a landowner upon the creation of an
oil and gas lease.
Lease: Full or partial interests in: (i) undeveloped oil and gas leases;
(ii) oil and gas mineral rights; (iii) licenses; (iv) concessions; (v)
contracts; (vi) fee rights; or (vii) other rights authorizing the owner
thereof to drill for, reduce to possession and produce oil and gas.
Limited Partners: Those Investor Partners who purchase Units as Limited
Partners, transferees or assignees who become Limited Partners, or
Additional General Partners who convert their interests to limited
partnership interests pursuant to the provisions of the Partnership
Agreement.
Loss: The excess of the Partnership's losses and deductions over the
Partnership's income and gains, computed in accordance with the provisions
of the Federal income tax laws.
Management Fee: The fee to which the Managing General Partner is entitled
pursuant to Section 6.06 of the Partnership Agreement.
Managing General Partner: Petroleum Development Corporation or its
successors.
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<PAGE>
Mcf: One thousand cubic feet of natural gas measured at the standard
temperature of 60 degrees Fahrenheit and pressure of 14.65 psi.
Net Subscriptions: An amount equal to total Subscriptions of the Investor
Partners less the amount of Organization and Offering Costs of the
Partnership.
Net Well: The sum of fractional Working Interests owned and drilled by
the Partnership.
Non-capital Expenditures: Those expenditures associated with property
acquisition and the drilling and completion of oil and gas wells that
under present law are generally accepted as fully deductible currently for
federal income tax purposes.
Offering Termination Date: December 31, 1996 with respect to Partnerships
designated "PDC 1996-_ Limited Partnership" and December 31, 1997 with
respect to Partnerships designated "PDC 1997-_ Limited Partnership" or
such earlier date as the Managing General Partner, in its sole and
absolute discretion, shall select.
Oil and Gas Interest: Any oil or gas royalty or lease, or fractional
interest therein, or certificate of interest or participation or
investment contract relative to such royalties, leases or fractional
interests, or any other interest or right which permits the exploration
of, drilling for, or production of oil and gas or other related
hydrocarbons or the receipt of such production or the proceeds thereof.
Operating Costs: Expenditures made and costs incurred in producing and
marketing oil or gas from completed wells, including, in addition to
labor, fuel, repairs, hauling, materials, supplies, utility charges and
other costs incident to or therefrom, ad valorem and severance taxes,
insurance and casualty loss expense, and compensation to well operators or
others for services rendered in conducting such operations.
Organization and Offering Costs: All costs of organizing and selling the
offering including, but not limited to, total underwriting and brokerage
discounts and commissions (including fees of the underwriters' attorneys),
expenses for printing, engraving, mailing, salaries of employees while
engaged in sales activity, charges of transfer agents, registrars,
trustees, escrow holders, depositaries, engineers and other experts,
expenses of qualification of the sale of the securities under federal and
state law, including taxes and fees, accountants' and attorneys' fees and
other frontend fees.
Overriding Royalty Interest: An interest in the oil and gas produced
pursuant to a specified oil and gas lease or leases, or the proceeds from
the sale thereof, carved out of the working interest, to be received free
and clear of all costs of development, operation, or maintenance.
Participant: The purchaser of a Unit in the Program.
Partners: The Managing General Partner, the Additional General Partners
other than the Managing General Partner, and the Limited Partners.
Reference to a "Partner" shall mean any one of the Partners.
Partnership or Partnerships: One or all of the limited partnerships to be
formed in the PDC 1996-1997 Drilling Program comprised of a series of up
to eight limited partnerships to be designated as the PDC 1996-A Limited
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<PAGE>
Partnership, the PDC 1996-B Limited Partnership, the PDC 1996-C Limited
Partnership, PDC 1996-D Limited Partnership, PDC 1997-A Limited
Partnership, PDC 1997-B Limited Partnership, PDC 1997-C Limited
Partnership, and PDC 1997-D Limited Partnership. The Partnerships will be
governed by the West Virginia Uniform Limited Partnership Act. Together
the Partnerships, for purposes of this offering, are referred to as the
PDC 1996-1997 Drilling Program or sometimes as the Program.
Partnership Agreement: The Limited Partnership Agreement as it may be
amended from time to time, the form of which is attached to the Prospectus
as Appendix A.
Partnership Minimum Gain: Partnership Minimum Gain as defined in Treas.
Reg. Section 1.704-2(d)(1).
PDC: Petroleum Development Corporation.
Profit: The excess of the Partnership's income and gains over the
Partnership's losses and deductions, computed in accordance with the
provisions of the Federal income tax laws.
Program: One or more limited partnerships formed, or to be formed, for
the primary purpose of exploring oil or gas. Herein, PDC 1996-1997
Drilling Program.
Prospect: A contiguous oil and gas leasehold estate, or lesser interest
therein, upon which drilling operations may be conducted. In general, a
Prospect is an area in which a Partnership owns or intends to own one or
more oil and gas interests, which is geographically defined on the basis
of geological data by the Managing General Partner and which is reasonably
anticipated by the Managing General Partner to contain at least one
reservoir. An area covering lands which are believed by the Managing
General Partner to contain subsurface structural or stratigraphic
conditions making it susceptible to the accumulations of hydrocarbons in
commercially productive quantities at one or more horizons. The area,
which may be different for different horizons, shall be designated by the
Managing General Partner in writing prior to the conduct of program
operations and shall be enlarged or contracted from time to time on the
basis of subsequently acquired information to define the anticipated
limits of the associated hydrocarbon reserves and to include all acreage
encompassed therein. A "prospect" with respect to a particular horizon
may be limited to the minimum area permitted by state law or local
practice, whichever is applicable, to protect against drainage from
adjacent wells if the well to be drilled by the Partnership is to a
horizon containing proved reserves.
Prospectus: The Partnership's Prospectus, including a preliminary
prospectus, of which the Partnership Agreement is a part, pursuant to
which the Units are being offered and sold.
Proved Developed Oil and Gas Reserves. Proved developed oil and gas
reserves are reserves that can be expected to be recovered through
existing wells with existing equipment and operating methods. Additional
oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as
"proved developed reserves" only after testing by a pilot project or after
the operation of an installed program has confirmed through production
response that increased recovery will be achieved.
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<PAGE>
Proved Oil and Gas Reserves: Proved oil and gas reserves are the
estimated quantities of crude oil, natural gas, and natural gas liquids
which geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under
existing economic and operating conditions, i.e., prices and costs as of
the date the estimate is made. Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation
test. The area of a reservoir considered proved includes (A)
that portion delineated by drilling and defined by gas-oil
and/or oil-water contacts, if any, and (B) the immediately
adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis of
available geological and engineering data. In the absence of
information on fluid contacts, the lowest known structural
occurrence of hydrocarbons controls the lower proved limit of
the reservoir.
(ii) Reserves which can be produced economically through application
of improved recovery techniques (such as fluid injection) are
included in the "proved" classification when successful testing
by a pilot project, or the operation of an installed program in
the reservoir, provides support for the engineering analysis on
which the project or program was based.
(iii) Estimates or proved reserves do not include the following: (A)
oil that may become available from known reservoirs but is
classified separately as "indicated additional reserves; (B)
crude oil, natural gas, and natural gas liquids, the recovery of
which is subject to reasonable doubt because of uncertainty as
to geology, reservoir characteristics, or economic factors; (C)
crude oil, natural gas, and natural gas liquids, that may occur
in undrilled prospects; and (D) crude oil, natural gas, and
natural gas liquids, that may be recovered from oil shales,
coal, gilsonite and other such sources.
Proved Undeveloped Reserves. Proved undeveloped oil and gas reserves are
reserves that are expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major expenditure is
required for recompletion. Reserves on undrilled acreage shall be limited
to those drilling units offsetting productive units that are reasonably
certain of production when drilled. Proved reserves for other undrilled
units can be claimed only where it can be demonstrated with certainty that
there is continuity of production from the existing productive formation.
Under no circumstances should estimates for proved undeveloped reserves be
attributable to any acreage for which an application of fluid injection or
other improved recovery technique is contemplated, unless such techniques
have been proved effective by actual tests in the area and in the same
reservoir.
Reservoir: A separate structural or stratigraphic trap containing an
accumulation of oil or gas.
Roll-Up: A transaction involving the acquisition, merger, conversion, or
consolidation, either directly or indirectly, of the Partnership and the
issuance of securities of a roll-up entity. Such term does not include:
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<PAGE>
(a) a transaction involving securities of the Partnership that have been
listed for at least 12 months on a national exchange or traded
through the National Association of Securities Dealers Automated
Quotation National Market System; or
(b) a transaction involving the conversion to corporate, trust or
association form of only the Partnership if, as a consequence of the
transaction, there will be no significant adverse change in any of
the following:
(1) voting rights;
(2) the term of existence of the Partnership;
(3) sponsor compensation; or
(4) the Partnership's investment objectives.
Roll-Up Entity: A partnership, trust, corporation or other entity that
would be created or survive after the successful completion of a proposed
roll-up transaction.
Royalty: A fractional undivided interest in the production of oil and gas
wells, or the proceeds therefrom to be received free and clear of all
costs of development, operations or maintenance. Royalties may be
reserved by landowners upon the creation of an oil and gas lease
("landowner's royalty") or subsequently carved out of a working interest
("overriding royalty").
Securities Act: Securities Act of 1933, as amended.
Sponsor: Any person directly or indirectly instrumental in organizing,
wholly or in part, a program or any person who will manage or is entitled
to manage or participate in the management or control of a program.
"Sponsor" includes the managing and controlling general partner(s) and any
other person who actually controls or selects the person who controls 25%
or more of the exploratory, developmental or producing activities of the
Partnership, or any segment thereof, even if that person has not entered
into a contract at the time of formation of the Partnership. "Sponsor"
does not include wholly independent third parties such as attorneys,
accountants, and underwriters whose only compensation is for professional
services rendered in connection with the offering of units. Whenever the
context of these guidelines so requires, the term "sponsor" shall be
deemed to include its affiliates.
Spudding Rule and Spudding Date: The date that drilling commences.
Subscriptions: The Subscription Agreement(s) or the amount indicated on
the Subscriptions Agreements that the Additional General Partners and the
Limited Partners have agreed to pay to a Partnership.
Tangible Costs: Those costs which are generally accepted as capital
expenditures pursuant to the provisions of the Code.
Treas. Reg.: A regulation promulgated by the Treasury Department under
Title 26 of the United States Code.
Unit: An undivided interest of the Investor Partners in the aggregate
interest in the capital and profits of the Partnership.
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<PAGE>
Well Head Gas Price: The price paid by a gas purchaser for gas produced
from Partnership wells excluding any tax reimbursements or transportation
allowances.
Working Interest: An interest in an oil and gas leasehold which is
subject to some portion of the costs of development, operation, or
maintenance.
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<PAGE>
PETROLEUM DEVELOPMENT CORPORATION
AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 1994 and 1993
(With Independent Auditors' Report Thereon)
<PAGE>
Independent Auditors' Report
The Stockholders and Board of Directors
Petroleum Development Corporation:
We have audited the accompanying consolidated balance sheets of Petroleum
Development Corporation and subsidiaries as of December 31, 1994 and 1993.
These consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on
these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the balance sheets are free of
material misstatement. An audit of a balance sheet includes examining, on
a test basis, evidence supporting the amounts and disclosures in that
balance sheet. An audit of a balance sheet also includes assessing the
accounting principles used and significant estimates made by management,
as well as evaluating the overall balance sheet presentation. We believe
that our audits of the balance sheets provide a reasonable basis for our
opinion.
In our opinion, the consolidated balance sheets referred to above present
fairly, in all material respects, the financial position of Petroleum
Development Corporation and subsidiaries as of December 31, 1994 and 1993,
in conformity with generally accepted accounting principles.
/s/ KPMG PEAT MARWICK LLP
KPMG PEAT MARWICK LLP
Pittsburgh, Pennsylvania
March 15, 1995
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 1994 and 1993
<TABLE>
<S> <S> <S>
1994 1993
Assets
Current assets:
Cash and cash equivalents $ 8,906,800 10,578,800
Accounts and notes receivable (note 2) 1,975,400 2,014,800
Inventories 390,200 352,100
Prepaid expenses 850,600 559,900
Total current assets 12,123,000 13,505,600
Properties and equipment (notes 1 and 3):
Oil and gas properties (successful
efforts accounting method) 35,051,300 30,429,100
Pipelines 6,525,200 6,066,700
Transportation and other equipment 2,540,100 2,508,700
Land and buildings 843,300 825,000
44,959,900 39,829,500
Less accumulated depreciation,
depletion and amortization 19,204,400 17,464,800
25,755,500 22,364,700
Other assets (note 2) 446,800 542,600
$38,325,300 36,412,900
</TABLE>
(Continued)
1
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 1994 and 1993
<TABLE>
<S> <S> <S>
Liabilities and Stockholders' Equity
Current liabilities:
Current maturities of long-term debt
(note 3) $ 36,300 68,300
Accounts payable 2,484,700 2,849,300
Accrued taxes 44,900 184,000
Other accrued expenses 1,604,200 1,146,000
Advances for future drilling contracts 9,199,900 8,128,000
Funds held for future distribution 366,700 841,000
Total current liabilities 13,736,700 13,216,600
Long-term debt, excluding current maturities
(note 3) 3,100,000 3,167,300
Other liabilities 328,600 190,900
Deferred income taxes (note 4) 2,779,500 2,602,400
Commitments and contingencies (note 7)
Stockholders' equity (note 5):
Common stock, par value $.01 per share;
authorized 22,250,000 shares; issued and
outstanding 11,040,627 and 10,831,921 110,400 108,300
Common stock, Class A, par value $.01 per
share; authorized 2,750,000 shares; issued
and outstanding - none - -
Additional paid-in capital 6,873,600 6,652,500
Retained earnings 11,396,500 10,474,900
Total stockholders' equity 18,380,500 17,235,700
$38,325,300 36,412,900
</TABLE>
AN INVESTOR IN PDC 1996-1997 DRILLING PROGRAM DOES NOT THEREBY
ACQUIRE ANY INTEREST IN THE ASSETS OF PETROLEUM DEVELOPMENT
CORPORATION
See accompanying notes to consolidated financial statements.
2
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
December 31, 1994 and 1993
(1) Summary of Significant Accounting Policies
Principles of Consolidation
The accompanying balance sheets include the accounts of Petroleum
Development Corporation and its wholly owned subsidiaries. All
material intercompany accounts and transactions have been
eliminated in consolidation. The Company accounts for its
investment in limited partnerships under the proportionate
consolidation method. Under this method, the Company's balance
sheets include its pro rata share of assets and liabilities of the
limited partnerships in which it participates.
The Company is principally involved in oil and gas exploration,
production and development and related property management which is
considered one business segment for financial reporting purposes.
The Company grants credit to purchasers of oil and gas and the owners
of managed properties, substantially all of whom are located in the
Appalachian Basin area of West Virginia, Tennessee, Pennsylvania
and Ohio.
Cash Equivalents
For purposes of the statement of cash flows, the Company considers
all highly liquid debt instruments with original maturities of
three months or less to be cash equivalents.
Inventories
Inventories of well equipment, parts and supplies are valued at the
lower of average cost or market.
Oil and Gas Properties
Exploration and development costs are accounted for by the successful
efforts method.
The Company compares the aggregate carrying value of its gas and oil
producing properties to estimated future undiscounted cash flows
from such properties (the "ceiling") in order to determine whether
the carrying value of such properties should be reduced.
Property acquisition costs are capitalized when incurred. Geological
and geophysical costs and delay rentals are expensed as incurred.
The costs of drilling exploratory wells are capitalized pending
determination of whether the wells have discovered economically
producible reserves. If reserves are not discovered, such costs
are expensed as dry holes. Development costs, including equipment
and intangible drilling costs related to both producing wells and
developmental dry holes, are capitalized.
Unproved properties are assessed on a property-by-property basis and
properties considered to be impaired are charged to expense when
such impairment is deemed to have occurred.
(Continued)
3
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
Costs of proved properties, including leasehold acquisition,
exploration and development costs and equipment, are depreciated or
depleted by the unit-of-production method based on estimated proved
developed oil and gas reserves.
Upon sale or retirement of complete units of depreciable or
depletable property, the net cost thereof, less proceeds or salvage
value, is credited or charged to income. Upon retirement of a
partial unit of property, the cost thereof is charged to
accumulated depreciation and depletion.
Transportation Equipment, Pipelines and Other Equipment
Transportation equipment, pipelines and other equipment are carried
at cost. Depreciation is provided principally on the straight-line
method over useful lives of 3 to 17 years.
Maintenance and repairs are charged to expense as incurred. Major
renewals and betterments are capitalized. Upon the sale or other
disposition of assets, the cost and related accumulated
depreciation, depletion and amortization are removed from the
accounts, the proceeds applied thereto and any resulting gain or
loss is reflected in income.
Buildings
Buildings are carried at cost and depreciated on the straight-line
method over estimated useful lives of 30 years.
Retirement Plans
The Company has a 401-K contributory retirement plan (401-K Plan)
covering full-time employees. The Company provides a discretionary
matching of employee contributions to the plan.
The Company also has a profit sharing plan covering full-time
employees. The Company's contributions to this plan are
discretionary.
During 1994, the Company established a deferred compensation
arrangement covering executive officers of the Company as a
supplemental retirement benefit.
Income Taxes
Deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and
their respective tax bases. Deferred tax assets and liabilities
are measured using enacted tax rates expected to apply to taxable
income in the years in which those temporary differences are
expected to be recovered or settled. The effect on deferred tax
assets and liabilities of a change in tax rates is recognized in
income in the period that includes the enactment date.
(Continued)
4
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
(2) Notes and Accounts Receivable
The Company holds notes receivable from officers, directors and
employees with interest from 8% to 12% as of December 31, 1994 and
1993, in the amounts of $41,900 and $42,200, respectively, of which
$8,700 and $200 are current.
Included in other assets are noncurrent notes and accounts receivable
as of December 31, 1994 and 1993, in the amounts of $368,000 and
$438,300, net of the allowance for doubtful accounts of $254,000
and $62,300, respectively.
The allowance for doubtful current accounts receivable as of December
31, 1994 and 1993 was $175,400 and $300,000, respectively.
(3) Long-Term Debt
Long-term debt at December 31, 1994 and 1993, consisted of the
following:
<TABLE>
<S> <S> <S>
1994 1993
Note payable to bank, under
a credit agreement, due in
November 1996 with interest
payable monthly at prime
(8.5% at December 31, 1994)
plus 1-1/4% $3,100,000 3,100,000
Mortgage note payable to bank
with interest at prime (8.5%
at December 31, 1994) plus
1-1/2%, due in monthly installments
of $2,700, secured by real property 28,200 72,800
Installment notes payable with various
interest rates ranging to 8.5%,
payable in monthly installments of
approximately $1,300 plus
interest through 1995,
secured by equipment 8,100 62,800
3,136,300 3,235,600
Current maturities 36,300 68,300
Long-term debt, excluding
current maturities $3,100,000 3,167,300
</TABLE>
On November 17, 1993, the Company entered into a Credit Agreement
providing a borrowing base of $7,500,000 subject to adequate natural
gas reserve levels.
(Continued)
5
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
The Company borrowed $3,350,000 under the agreement and prepaid
$1,555,400 to retire the outstanding obligation under its previously
existing credit agreement. Additionally, $1,756,000 was used to
repurchase 1,243,073 shares of the Company's common stock owned by the
lender pursuant to the exercise of warrants issued in 1990.
The Credit Agreement requires no principal payments until it matures in
November, 1996. The Company has activated $5,000,000 of the credit
line and is required to pay an annual commitment fee of 1/2% on the
unused portion of the activated credit facility. The loan is secured
by substantially all properties and equipment of the Company. The
Credit Agreement requires the existence of satisfactory levels of
natural gas reserves, and additionally provides, among other things,
for the maintenance of certain working capital and tangible net worth
ratios along with limitations on dividend payments. All long-term
debt at December 31, 1994 matures in 1996.
(4) Income Taxes
The tax effects of temporary differences that give rise to
significant portions of the deferred tax assets and deferred tax
liabilities at December 31, 1994 and 1993 are presented below:
<TABLE>
<S> <S> <S>
1994 1993
Deferred tax assets:
Drilling notes, principally
due to allowance for
doubtful accounts $ 839,700 1,104,900
Investment tax credit
carryforwards 342,100 364,300
Alternative minimum tax
credit carryforwards
(Section 29) 698,600 632,000
Other 340,200 271,400
Total gross deferred tax assets 2,220,600 2,372,600
Less valuation allowance (842,700) (797,700)
Deferred tax assets 1,377,900 1,574,900
Less current deferred tax assets
(included in prepaid
expenses) (275,000) (195,300)
Net non-current deferred
tax assets 1,102,900 1,379,600
Deferred tax liabilities:
Plant and equipment,
principally due to
differences in depreciation
and amortization (3,882,400) (3,982,000)
Total gross deferred
tax liabilities (3,882,400) (3,982,000)
Net deferred tax liability $(2,779,500) (2,602,400)
</TABLE>
The Company has evaluated each deferred tax asset and has provided a
valuation allowance where it is believed more likely than not that
some portion of the asset will not be realized.
(Continued)
6
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
The valuation allowance for deferred tax assets as of January 1, 1993
was $698,000. The net changes in the total valuation allowance for
the years ended December 31, 1994 and 1993 were increases of $45,000
and $99,700, respectively.
At December 31, 1994, the Company has investment tax credit
carryforwards for federal income tax purposes of approximately
$342,100 which are available to reduce future federal income taxes,
if any, through 2000. In addition, the Company has alternative
minimum tax credit carryforwards (Section 29) of approximately
$698,600 which are available to reduce future federal regular income
taxes, if any, over an indefinite period.
(5) Common Stock
Changes in capital during 1994 and 1993 are as follows:
<TABLE>
<S> <S> <S> <S> <S>
Common stock
issued
Number Additional
of Paid-In
Retained
Shares Amount Capital
Earnings
Balance,
December 31, 1992 10,027,903 100,200 $6,361,800 $
8,885,100
Issuance of common stock:
Exercise of employee
stock options 142,960 1,500 39,200 -
Exercise of warrants 1,993,073 19,900 1,980,100 -
Purchase of
treasury stock (1,424,323) (14,200) (1,877,700) -
Reissuance of treasury
stock to profit
sharing plan 92,308 900 149,100 -
Net Income - - -
1,589,800
Balance,
December 31, 1993 10,831,921 108,300 6,652,500 10,474,900
Issuance of common stock:
Purchase of properties 55,000 500 109,500 -
Exercise of employee
stock options 153,706 1,600 111,600 -
Net income - - - 921,600
Balance,
December 31, 1994 11,040,627 $110,400 $6,873,600 $11,396,500
</TABLE>
Warrants
The Company had outstanding warrants to purchase 2,750,000 shares of its
common stock at $.50 per share which were issued in connection with a 1990
(Continued)
7
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
debt restructuring. During 1993, the Company paid off its existing debt
and entered into an agreement whereby the holder exercised warrants for
1,993,073 shares and surrendered warrants for 756,927 shares in lieu of a
cash payment in connection with the warrants exercised. The Company
repurchased and retired 1,243,073 of these shares for $1,756,000. The
Company obtained an option to acquire an additional 250,000 of these
shares until June 30, 1995 at 10% below market price. As of December 31,
1993 there are no warrants outstanding.
Options
During 1993, options amounting to 128,500 shares were granted to certain
employees and directors under the Company's Stock Option Plans. These
options were granted at market value as of the date of grant and the
outstanding options expire from 1995 to 2000.
<TABLE>
<S> <S> <S> <S> <S> <S>
<S>
1994
1993
Number Number
of Shares Average Range of Shares Average
Range
Outstanding at
beginning of
year 2,182,250 $ .71 .38 - 1.63 2,398,750 $ .64
.38 - 1.00
Granted - $ - - 128,500 $1.63
1.63 - 1.63
Exercised (226,250) $ .50 .44 - .69 (156,000) $ .42
.38 - .65
Expired - $ - - (189,000) $ .64
.55 - .72
Outstanding
and exercisable
at end of
year 1,956,000 $ .77 .38 -1.63 2,182,250 $ .71
.38 - 1.63
</TABLE>
Stock Redemption Agreement
The Company has stock redemption agreements with three officers of the
Company. The agreements require the Company to maintain life
insurance on each executive in the amount of $1,000,000. The
agreements provide that the Company shall utilize the proceeds from
such insurance to purchase from such executives' estates or heirs, at
their option, shares of the Company's stock. The purchase price for
the outstanding common stock is to be based upon the average closing
asked price for the Company's stock as quoted by NASDAQ during a
specified period. The Company is not required to purchase any shares
in excess of the amount provided for by such insurance.
(Continued)
8
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
(6) Transactions with Affiliates
As part of its duties as well operator, the Company received
$12,834,300 in 1994 and $11,894,200 in 1993 representing proceeds
from the sale of oil and gas and made distributions to investor
groups according to their working interests in the related oil and
gas properties.
(7) Commitments and Contingencies
The nature of the independent oil and gas industry involves a
dependence on outside investor drilling capital and involves a
concentration of gas sales to a few customers. The Company sells
natural gas to various public utilities and industrial customers,
none of which accounted for more than 10% of total revenues.
The Company is the general partner in various gas and oil limited
partnerships and has unlimited liability to third parties with
respect to the operations of the partnerships. Management believes
this obligation will not have a material effect on the Company's
financial statement.
The Company is party to various legal actions in the normal course of
business which would not materially affect the Company's
operations.
(8) Costs Incurred in Oil and Gas Property Acquisition, Exploration and
Development Activities
Costs incurred by the Company in oil and gas property acquisition,
exploration and development are presented below:
<TABLE>
Years Ended December 31,
<S> <S> <S>
1994 1993
Property acquisition cost:
Proved undeveloped
properties $ 426,200 267,500
Producing properties 1,332,100 59,700
Exploration costs - 97,800
Development costs 2,260,800 1,412,000
$4,019,100 1,837,000
</TABLE>
Property acquisition costs include costs incurred to purchase, lease
or otherwise acquire a property. Exploration costs include the
cost of geological and geophysical activity, dry holes and drilling
and equipping exploratory wells. Development costs include costs
incurred to gain access to and prepare development well locations
for drilling, to drill and equip development wells and to provide
facilities to extract, treat, gather and store oil and gas.
(Continued)
9
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
(9) Oil and Gas Capitalized Costs
Aggregate capitalized costs for the Company related to oil and gas
exploration and production activities with applicable accumulated
depreciation, depletion and amortization are presented below:
<TABLE>
<S> <S> <S>
December 31,
1994 1993
Proved properties:
Intangible drilling cost $16,363,400 15,063,400
Tangible well equipment 13,854,200 10,546,300
Well equipment leased to others 4,063,600 4,063,600
Undeveloped properties 770,100 755,800
35,051,300 30,429,100
Less accumulated depreciation,
depletion and amortization 13,021,600 11,793,900
$22,029,700 18,635,200
</TABLE>
(10) Net Proved Oil and Gas Reserves (Unaudited)
The proved reserves of oil and gas of the Company as estimated by the
Company, all of which are located within the United States, are as
follows:
<TABLE>
<S> <S> <S>
Oil (BBLS)
1994 1993
Proved developed and
undeveloped reserves:
Beginning of year 91,000 78,000
Beginning of previous year (1,000) 23,000
Beginning of year as revised 90,000 101,000
Production (11,000) (10,000)
End of year 79,000 91,000
Proved developed reserves:
Beginning of year 90,000 78,000
End of year 79,000 91,000
Gas (MCF)
1994 1993
Proved developed and
undeveloped reserves:
Beginning of year 24,660,000 24,980,000
Revisions of previous
estimates 4,472,000 (889,000)
Beginning of year as revised 29,132,000 24,091,000
New discoveries and
extensions 2,345,000 1,534,000
Acquisitions 1,943,000 -
Production (1,195,000) (965,000)
End of year 32,225,000 24,660,000
Proved developed reserves: 20,181,000 20,477,000
End of year 27,746,000 20,181,000
</TABLE>
(Continued)
10
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
(11) Standardized Measure of Discounted Future Net Cash Flows and Changes
Therein Relating to Proved Oil and Gas Reserves (Unaudited)
Summarized in the following table is information for the Company with
respect to the standardized measure of discounted future net cash
flows relating to proved oil and gas reserves. Future cash inflows
are derived by applying current oil and gas prices to estimated
future production. Future production and development costs are
derived based on current costs assuming continuation of existing
economic conditions. Future income tax expenses are computed by
applying the statutory rate in effect at the end of each year to
the future pretax net cash flows, less the tax basis of the
properties and gives effect to permanent differences, tax credits
and allowances related to the properties.
<TABLE>
<S> <S> <S>
Years Ended December 31,
1994 1993
Future estimated cash flows $73,316,000 64,588,000
Future estimated production
and development costs (24,370,000) (18,736,000)
Future estimated income
tax expense (13,950,000) (13,068,000)
Future net cash flows 34,996,000 32,784,000
10% annual discount for
estimated timing of cash
flows (20,551,000) (18,766,000)
Standardized measure of
discounted future
estimated net cash $14,445,000 14,018,000
</TABLE>
The following table summarizes the principal sources of change in the
standardized measure of discounted future estimated net cash flows:
<TABLE>
<S> <S> <S>
Years Ended December 31,
1994 1993
Sales of oil and gas
production, net of
production costs $(1,875,000) (1,621,000)
Net changes in prices
and production costs (9,560,000) (6,046,000)
Extensions, discoveries
and improved recovery,
less related cost 3,875,000 2,818,000
Acquisitions 2,745,000 -
Development costs incurred
during the period 2,261,000 1,412,000
Revisions of previous
quantity estimates 8,222,000 (1,607,000)
Changes in estimated
income taxes (882,000) 3,803,000
Accretion of discount (1,785,000) 1,572,000
Other (2,574,000) (1,828,000)
$ 427,000 (1,497,000)
</TABLE>
(Continued)
11
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets (Continued)
It is necessary to emphasize that the data presented should not be
viewed as representing the expected cash flow from, or current
value of, existing proved reserves since the computations are
based on a large number of estimates and arbitrary assumptions.
Reserve quantities cannot be measured with precision and their
estimation requires many judgmental determinations and frequent
revisions. The required projection of production and related
expenditures over time requires further estimates with respect to
pipeline availability, rates of demand and governmental control.
Actual future prices and costs are likely to be substantially
different from the current prices and costs utilized in the
computation of reported amounts. Any analysis or evaluation of the
reported amounts should give specific recognition to the
computational methods utilized and the limitations inherent
therein.
12
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
September 30, 1995 and December 31, 1994
<TABLE>
<S> <S> <S>
1995 1994
(unaudited)
Assets
Current assets:
Cash and cash equivalents $2,333,600 $ 8,906,800
Accounts and notes receivable 1,633,900 1,975,400
Inventories 192,700 390,200
Prepaid expenses 784,400 850,600
Total current assets 4,944,600 12,123,000
Properties and equipment 46,005,000 44,959,900
Less accumulated depreciation,
depletion and amortization 20,731,300 19,204,400
25,273,700 25,755,500
Other assets 278,700 446,800
$30,497,000 $38,325,300
Liabilities and Stockholders' Equity
Current liabilities:
Current maturities of
long-term debt $ 6,500 $ 36,300
Accounts payable and
accrued expenses 3,835,900 4,133,800
Advances for future
drilling contracts 900,100 9,199,900
Funds held for future
distribution 326,300 366,700
Total current liabilities 5,068,800 13,736,700
Long-term debt, excluding
current maturities 2,700,000 3,100,000
Other liabilities 469,900 328,600
Deferred income taxes 2,878,400 2,779,500
Commitments and contingencies
Stockholders' equity:
Common stock 110,400 110,400
Additional paid-in capital 6,873,600 6,873,600
Retained earnings 12,395,900 11,396,500
Total stockholders'
equity 19,379,900 18,380,500
$30,497,000 $38,325,300
</TABLE>
AN INVESTOR IN PDC 1996-1997 DRILLING PROGRAM DOES NOT THEREBY ACQUIRE
ANY INTEREST IN THE ASSETS OF PETROLEUM DEVELOPMENT CORPORATION
See accompanying notes to consolidated balance sheets.
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED BALANCE SHEETS
1. Accounting Policies
Reference is hereby made to the Company's audited Consolidated Balance
Sheet at December 31, 1994, which contains a summary of significant
accounting policies followed by the Company in preparation of its
consolidated financial statements. These policies were also followed in
preparing the unaudited balance sheet at September 30, 1995 included herein.
2. Basis of Presentation
The Management of the Company believes that all adjustments (consisting of
only normal recurring accruals) necessary to a fair statement of the
financial position of the Company as of September 30, 1995 have been made.
3. Oil and Gas Properties
Oil and Gas Properties are reported on the successful efforts method.
4. Contingencies and Commitments
There are no material loss contingencies at September 30, 1995. There has been
no change in commitments and contingencies as described in Note 10 to the
Consolidated Balance Sheet at December 31, 1994.
AN INVESTOR IN PDC 1996-1997 DRILLING PROGRAM DOES NOT THEREBY ACQUIRE
ANY INTEREST IN THE ASSETS OF PETROLEUM DEVELOPMENT CORPORATION
<PAGE>
APPENDIX A
FORM OF
LIMITED PARTNERSHIP AGREEMENT
OF
PDC 1996-___ LIMITED PARTNERSHIP
[PDC 1997-___ LIMITED PARTNERSHIP]
<PAGE>
TABLE OF CONTENTS
Page
APPENDIX A
FORM OF
LIMITED PARTNERSHIP AGREEMENT
OF
PDC 1996-___ LIMITED PARTNERSHIP
[PDC 1997-___ LIMITED PARTNERSHIP]
<PAGE>
TABLE OF CONTENTS
Page
ARTICLE I: The Partnership . . . . . . . . . . . . . . . . 1
1.01 Organization. . . . . . . . . . . . . . . . . . . 1
1.02 Partnership Name. . . . . . . . . . . . . . . . . 1
1.03 Character of Business . . . . . . . . . . . . . . 1
1.04 Principal Place of Business . . . . . . . . . . . 1
1.05 Term of Partnership . . . . . . . . . . . . . . . 2
1.06 Filings . . . . . . . . . . . . . . . . . . . . . 2
1.07 Independent Activities . . . . . . . . . . . . . 2
1.08 Definitions . . . . . . . . . . . . . . . . . . . 3
ARTICLE II: Capitalization. . . . . . . . . . . . . . . . . . 12
2.01 Capital Contributions of the Managing General
Partner and Initial Limited Partner . . . . . . . 12
2.02 Capital Contributions of the Investor
Partners. . . . . . . . . . . . . . . . . . . . . 12
2.03 Additional Contributions. . . . . . . . . . . . . 13
ARTICLE III: Capital Accounts and Allocations. . . . . . . . . 14
3.01 Capital Accounts. . . . . . . . . . . . . . . . . 14
3.02 Allocation of Profits and Losses. . . . . . . . . 16
3.03 Depletion . . . . . . . . . . . . . . . . . . . . 22
3.04 Apportionment Among Partners. . . . . . . . . . . 22
ARTICLE IV: Distributions . . . . . . . . . . . . . . . . . . 23
4.01 Time of Distribution. . . . . . . . . . . . . . . 23
4.02 Distributions . . . . . . . . . . . . . . . . . . 23
4.03 Capital Account Deficits. . . . . . . . . . . . . 23
4.04 Liability Upon Receipt of Distributions . . . . . 24
ARTICLE V: Activities. . . . . . . . . . . . . . . . . . . . 24
5.01 Management. . . . . . . . . . . . . . . . . . . . 24
5.02 Conduct of Operations . . . . . . . . . . . . . . 24
5.03 Acquisition and Sale of Leases. . . . . . . . . . 26
5.04 Title to Leases . . . . . . . . . . . . . . . . . 27
5.05 Farmouts. . . . . . . . . . . . . . . . . . . . . 27
5.06 Release, Abandonment, and Sale or Exchange
of Properties . . . . . . . . . . . . . . . . . . 28
5.07 Certain Transactions. . . . . . . . . . . . . . . 28
ARTICLE VI: Managing General Partner. . . . . . . . . . . . . 33
6.01 Managing General Partner. . . . . . . . . . . . . 33
6.02 Authority of Managing General
Partner . . . . . . . . . . . . . . . . . . . . . 34
6.03 Certain Restrictions on Managing General
Partner's Power and Authority . . . . . . . . . . 35
6.04 Indemnification of Managing General
Partner . . . . . . . . . . . . . . . . . . . . . 37
6.05 Withdrawal. . . . . . . . . . . . . . . . . . . . 38
i
<PAGE>
6.06 Management Fee. . . . . . . . . . . . . . . . . . 39
6.07 Tax Matters and Financial Reporting
Partner . . . . . . . . . . . . . . . . . . . . . 39
ARTICLE VII: Investor Partners . . . . . . . . . . . . . . . . 39
7.01 Management. . . . . . . . . . . . . . . . . . . . 39
7.02 Indemnification of Additional
General Partners. . . . . . . . . . . . . . . . . 40
7.03 Assignment of Units . . . . . . . . . . . . . . . 40
7.04 Prohibited Transfers . . . . . . . . . . . . . . 42
7.05 Withdrawal by Investor Partners . . . . . . . . . 42
7.06 Removal of Managing General Partner . . . . . . . 42
7.07 Calling of Meetings . . . . . . . . . . . . . . . 43
7.08 Additional Voting Rights. . . . . . . . . . . . . 43
7.09 Voting by Proxy . . . . . . . . . . . . . . . . . 44
7.10 Conversion of Additional General Partner
Interests into Limited Partner
Interests . . . . . . . . . . . . . . . . . . . . 44
7.11 Unit Repurchase Program . . . . . . . . . . . . . 45
7.12 Liability of Partners . . . . . . . . . . . . . . 46
ARTICLE VIII: Books and Records. . . . . . . . . . . . . . . . .46
8.01 Books and Records . . . . . . . . . . . . . . . . 46
8.02 Reports . . . . . . . . . . . . . . . . . . . . . 47
8.03 Bank Accounts . . . . . . . . . . . . . . . . . . 49
8.04 Federal Income Tax Elections. . . . . . . . . . . 49
ARTICLE IX: Dissolution; Winding-up . . . . . . . . . . . . . 49
9.01 Dissolution . . . . . . . . . . . . . . . . . . . 49
9.02 Liquidation . . . . . . . . . . . . . . . . . . . 50
9.03 Winding-up . . . . . . . . . . . . . . . . . . . 51
ARTICLE X: Power of Attorney . . . . . . . . . . . . . . . . 52
10.01 Managing General Partner as Attorney-in-Fact. . . 52
10.02 Nature as Special Power . . . . . . . . . . . . . 53
ARTICLE XI: Miscellaneous Provisions. . . . . . . . . . . . . 53
11.01 Liability of Parties. . . . . . . . . . . . . . . 53
11.02 Notices . . . . . . . . . . . . . . . . . . . . . 53
11.03 Paragraph Headings. . . . . . . . . . . . . . . . 53
11.04 Severability. . . . . . . . . . . . . . . . . . . 54
11.05 Sole Agreement. . . . . . . . . . . . . . . . . . 54
11.06 Applicable Law. . . . . . . . . . . . . . . . . . 54
11.07 Execution in Counterparts . . . . . . . . . . . . 54
11.08 Waiver of Action for Partition. . . . . . . . . . 54
11.09 Amendments. . . . . . . . . . . . . . . . . . . . 54
11.10 Consent to Allocations and Distributions. . . . . 55
11.11 Ratification. . . . . . . . . . . . . . . . . . . 55
11.12 Substitution of Signature Pages . . . . . . . . . 55
11.13 Incorporation by Reference. . . . . . . . . . . . 55
Signature Page . . . . . . . . . . . . . . . . . .56
ii
<PAGE>
FORM OF
LIMITED PARTNERSHIP AGREEMENT
OF PDC 1996-____ LIMITED PARTNERSHIP,
[PDC 1997-____LIMITED PARTNERSHIP,]
A WEST VIRGINIA LIMITED PARTNERSHIP
This LIMITED PARTNERSHIP AGREEMENT (the "Agreement") is made as of this
___ day of ___________, 1996 [1997] by and among Petroleum Development
Corporation, a Nevada corporation, as managing general partner (the
"Managing General Partner"), Steven R. Williams, a resident of West
Virginia, as the Initial Limited Partner, and the Persons whose names are
set forth on Exhibit A attached hereto, as additional general partners
(the "Additional General Partners") or as limited partners (the "Limited
Partners" and, collectively with Additional General Partners, the
"Investor Partners"), pursuant to the provisions of the West Virginia
Uniform Limited Partnership Act (the "Act"), on the following terms and
conditions:
ARTICLE I
The Partnership
1.01 Organization. Subject to the provisions of this Agreement, the
parties hereto do hereby form a limited partnership (the "Partnership")
pursuant to the provisions of the Act. The Partners hereby agree to
continue the Partnership as a limited partnership pursuant to the
provisions of the Act and upon the terms and conditions set forth in this
Agreement.
1.02 Partnership Name. The name of the Partnership shall be PDC 1996-
___ Limited Partnership, [PDC 1997-_ Limited Partnership,] a West Virginia
limited partnership, and all business of the Partnership shall be
conducted in such name. The Managing General Partner may change the name
of the Partnership upon ten days notice to the Investor Partners. The
Partnership shall hold all of its property in the name of the Partnership
and not in the name of any Partner.
1.03 Character of Business. The principal business of the Partnership
shall be to acquire Leases, drill sites, and other interests in oil and/or
gas properties and to drill for oil, gas, hydrocarbons, and other minerals
located in, on, or under such properties, to produce and sell oil, gas,
hydrocarbons, and other minerals from such properties, and to invest and
generally engage in any and all phases of the oil and gas business. Such
business purpose shall include without limitation the purchase, sale,
acquisition, disposition, exploration, development, operation, and
production of oil and gas properties of any character. The Partnership
shall not acquire property in exchange for Units. Without limiting the
foregoing, Partnership activities may be undertaken as principal, agent,
general partner, syndicate member, joint venturer, participant, or
otherwise.
1.04 Principal Place of Business. The principal place of business of
the Partnership shall be at 103 East Main Street, Bridgeport, West
Virginia, 26330. The Managing General Partner may change the principal
place of business of the Partnership to any other place within the State
of West Virginia upon ten days notice to the Investor Partners.
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1.05 Term of Partnership. The Partnership shall commence on the date
the Partnership is organized, as set forth in Section 1.01, and shall
continue until terminated as provided in Article IX hereof.
Notwithstanding the foregoing, if Investor Partners agreeing to purchase
$1,000,000 in Units have not subscribed and paid for their Units by the
Offering Termination Date, then this Agreement shall be void in all
respects, and all investments of the Investor Partners shall be promptly
returned together with any interest earned thereon and without any
deduction therefrom. The Managing General Partner and its Affiliates may
purchase up to 10% (and no more) of the Units subscribed for by Investor
Partners in the Partnership; however, not more than $50,000 of the Units
purchased by the Managing General Partner and/or its Affiliates will be
applied to satisfying the $1,000,000 minimum. The Units so purchased by
the Managing General Partner and/or its Affiliates will be counted toward
satisfying the minimum subscription amount.
1.06 Filings.
(a) A Certificate of Limited Partnership (the "Certificate") has been
filed in the office of the Secretary of State of West Virginia in
accordance with the provisions of the Act. The Managing General Partner
shall take any and all other actions reasonably necessary to perfect and
maintain the status of the Partnership as a limited partnership under the
laws of West Virginia. The Managing General Partner shall cause
amendments to the Certificate to be filed whenever required by the Act.
(b) The Managing General Partner shall execute and cause to be filed
original or amended Certificates and shall take any and all other actions
as may be reasonably necessary to perfect and maintain the status of the
Partnership as a limited partnership or similar type of entity under the
laws of any other states or jurisdictions in which the Partnership engages
in business.
(c) The agent for service of process on the Partnership shall be Steven
R. Williams or any successor as appointed by the Managing General Partner.
(d) Upon the dissolution of the Partnership, the Managing General
Partner (or any successor managing general partner) shall promptly execute
and cause to be filed certificates of dissolution in accordance with the
Act and the laws of any other states or jurisdictions in which the
Partnership has filed certificates.
1.07 Independent Activities. Each General Partner and each Limited
Partner may, notwithstanding this Agreement, engage in whatever activities
they choose, whether the same are competitive with the Partnership or
otherwise, without having or incurring any obligation to offer any
interest in such activities to the Partnership or any Partner. However,
except as otherwise provided herein, the Managing General Partner and any
of its Affiliates may pursue business opportunities that are consistent
with the Partnership's investment objectives for their own account only
after they have determined that such opportunity either cannot be pursued
by the Partnership because of insufficient funds or because it is not
appropriate for the Partnership under the existing circumstances. Neither
this Agreement nor any activity undertaken pursuant hereto shall prevent
the Managing General Partner from engaging in such activities, or require
the Managing General Partner to permit the Partnership or any Partner to
participate in any such activities, and as a material part of the
consideration for the execution of this Agreement by the Managing General
Partner and the admission of each Investor Partner, each Investor Partner
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hereby waives, relinquishes, and renounces any such right or claim of
participation. Notwithstanding the foregoing, the Managing General
Partner still has an overriding fiduciary obligation to the Investor
Partners.
1.08 Definitions. Capitalized words and phrases used in this Agreement
shall have the following meanings:
(a) "Act" shall mean the Uniform Limited Partnership Act of the State
of West Virginia, as set forth in Sections 47-9-1 through 47-9-63 thereof,
as amended from time to time (or any corresponding provisions of
succeeding law).
(b) "Additional General Partner" shall mean an Investor Partner who
purchases Units as an additional general partner, and such partner's
transferees and assigns. "Additional General Partners" shall mean all
such Investor Partners. "Additional General Partner" shall not include,
after a conversion, such Investor Partner who converts his interest into
a Limited Partnership interest pursuant to Section 7.10 herein.
(c) "Administrative Costs" shall mean all customary and routine expenses
incurred by the Managing General Partner for the conduct of program
administration, including legal, finance, accounting, secretarial, travel,
office rent, telephone, data processing and other items of a similar
nature.
(d) "Affiliate" shall mean an affiliate of a specified person means (a)
any person directly or indirectly owning, controlling, or holding
with power to vote 10 percent or more of the outstanding voting
securities of such specified person; (b) any person 10 percent or
more of whose outstanding voting securities are directly or
indirectly owned, controlled, or held with power to vote, by such
specified person; (c) any person directly or indirectly
controlling, controlled by, or under common control with such
specified person; (d) any officer, director, trustee or partner of
such specified person, and (e) if such specified person is an
officer, director, trustee or partner, any person for which such
person acts in any such capacity.
(e) "Agreement" or "Partnership Agreement" shall mean this Limited
Partnership Agreement, as amended from time to time.
(f) "Capital Account" shall mean, with respect to any Partner, the
capital account maintained for such Partner pursuant to Section 3.01
hereof.
(g) "Capital Contribution" shall mean, the total investment, including
the original investment, assessments, and amounts reinvested, by such
Investor Partner to the capital of the Partnership pursuant to Section
2.02 herein, and, with respect to the Managing General Partner and the
Initial Limited Partner, the total investment, including the original
investment, assessments, and amounts reinvested, to the capital of the
Partnership pursuant to Section 2.01 herein.
(h) "Code" shall mean the Internal Revenue Code of 1986, as amended
from time to time (or any corresponding provisions of succeeding law).
(i) "Cost," when used with respect to the sale of property to the
Partnership, shall mean (a) the sum of the prices paid by the seller to an
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unaffiliated person for such property, including bonuses; (b) title
insurance or examination costs, brokers' commissions, filing fees,
recording costs, transfer taxes, if any, and like charges in connection
with the acquisition of such property; (c) a pro rata portion of the
seller's actual necessary and reasonable expenses for seismic and
geophysical services; and (d) rentals and ad valorem taxes paid by the
seller with respect to such property to the date of its transfer to the
buyer, interest and points actually incurred on funds used to acquire or
maintain such property, and such portion of the seller's reasonable,
necessary and actual expenses for geological, engineering, drafting,
accounting, legal and other like services allocated to the property cost
in conformity with generally accepted accounting principles and industry
standards, except for expenses in connection with the past drilling of
wells which are not producers of sufficient quantities of oil or gas to
make commercially reasonable their continued operations, and provided that
the expenses enumerated in this subsection (d) hereof shall have been
incurred not more than 36 months prior to the purchase by the Partnership;
provided that such period may be extended, at the discretion of the state
securities administrator, upon proper justification, When used with
respect to services, "cost" means the reasonable, necessary and actual
expense incurred by the seller on behalf of the Partnership in providing
such services, determined in accordance with generally accepted accounting
principles. As used elsewhere, "cost" means the price paid by the seller
in an arm's-length transaction.
(j) "Depreciation" shall mean, for each fiscal year or other period,
an amount equal to the depreciation, amortization, or other cost recovery
deduction allowable with respect to an asset for such year or other
period, except that if the Gross Asset Value of an asset differs from its
adjusted basis for federal income tax purposes at the beginning of such
year or other period, Depreciation shall be an amount which bears the same
ratio to such beginning Gross Asset Value as the federal income tax
depreciation, amortization, or other cost recovery deduction for such year
or other period bears to such beginning adjusted tax basis; provided,
however, that if the federal income tax depreciation, amortization, or
other cost recovery deduction for such year is zero, Depreciation shall be
determined with reference to such beginning Gross Asset Value using any
reasonable method selected by the Managing General Partner.
(k) "Development Well" shall mean a well drilled within the proved area
of an oil or gas reservoir to the depth of a stratigraphic horizon known
to be productive.
(l) "Direct Costs" shall mean all actual and necessary costs directly
incurred for the benefit of the Partnership and generally attributable to
the goods and services provided to the Partnership by parties other than
the Managing General Partner or its Affiliates. Direct costs shall not
include any cost otherwise classified as organization and offering
expenses, administrative costs, operating costs or property costs. Direct
costs may include the cost of services provided by the Managing General
Partner or its Affiliates if such services are provided pursuant to
written contracts and in compliance with Section 5.07(e) of the
Partnership Agreement.
(m) "Drilling and Completion Costs" shall mean all costs, excluding
Operating Costs, of drilling, completing, testing, equipping and bringing
a well into production or plugging and abandoning it, including all labor
and other construction and installation costs incident thereto, location
and surface damages, cementing, drilling mud and chemicals, drillstem
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tests and core analysis, engineering and well site geological expenses,
electric logs, costs of plugging back, deepening, rework operations,
repairing or performing remedial work of any type, costs of plugging and
abandoning any well participated in by the Partnership, and reimbursements
and compensation to well operators, including charges paid to the Managing
General Partner as unit operator during the drilling and completion phase
of a well, plus the cost of the gathering system and of acquiring
leasehold interests.
(n) "Dry Hole" shall mean any well abandoned without having produced
oil or gas in commercial quantities.
(o) "Exploratory Well" shall mean a well drilled to find commercially
productive hydrocarbons in an unproved area, to find a new commercially
productive horizon in a field previously found to be productive of
hydrocarbons at another horizon, or to significantly extend a known
prospect.
(p) "Farmout" shall mean an agreement whereby the owner of the leasehold
or working interest agrees to assign his interest in certain specific
acreage to the assignees, retaining some interest such as an overriding
royalty interest, an oil and gas payment, offset acreage or other type of
interest, subject to the drilling of one or more specific wells or other
performance as a condition of the assignment.
(q) "General Partners" shall mean the Additional General Partners and
the Managing General Partner.
(r) "Gross Asset Value" shall mean, with respect to any asset, the
asset's adjusted basis for federal income tax purposes, except as follows:
(1) The initial Gross Asset Value of any asset contributed by
a Partner to the Partnership shall be the gross fair market
value of such asset, as determined by the contributing Partner
and the Partnership;
(2) The Gross Asset Values of all Partnership assets shall be
adjusted to equal their respective gross fair market
values, as determined by the Managing General Partner,
as of the following times: (a) the acquisition of an
additional interest in the Partnership by any new or
existing Partner in exchange for more than a de minimis
Capital Contribution; (b) the distribution by the
Partnership Property as consideration for an interest in
the Partnership; and (c) the liquidation of the Partnership
within the meaning of Treas. Reg. Section 1.704-1(b)
(2)(ii)(g); provided, however, that the adjustments
pursuant to clauses (a) and (b) above shall be made only if
the Managing General Partner reasonably determines that
such adjustments are necessary or appropriate to reflect
the relative economic interests of the Partners in the
Partnership;
(3) The Gross Asset Value of any Partnership asset distributed
to any Partner shall be the gross fair market value of
such asset on the date of distribution; and
(4) The Gross Asset Values of Partnership assets shall be
increased (or decreased) to reflect any adjustments to the
adjusted basis of such assets pursuant to Code Section 734(b)
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or Code Section 743(b), but only to the extent that such
adjustments are taken into account in determining Capital
Accounts pursuant to Treas. Reg. Section 1.704-1(b)(2)
(iv)(m) and Section 3.02(g) hereof; provided, however,
that Gross Asset Values shall not be adjusted pursuant
to this Section (4) to the extent the Managing General
Partner determines that an adjustment pursuant to Section
(2) hereof is necessary or appropriate in connection
with a transaction that would otherwise result in an
adjustment pursuant to this Section (4).
If the Gross Asset Value of an asset has been determined or adjusted
pursuant to Section (i), Section (ii), or (iv) hereof, such Gross Asset
value shall thereafter be adjusted by the Depreciation taken into account
with respect to such asset for purposes of computing Profits and Losses.
(s) "IDC" shall mean intangible drilling and development costs.
(t) "Independent Expert" shall mean a person with no material
relationship with the Managing General Partner or its Affiliates who is
qualified and who is in the business of rendering opinions regarding the
value of oil and gas properties based upon the evaluation of all pertinent
economic, financial, geologic and engineering information available to the
Managing General Partner or its Affiliates.
(u) "Initial Limited Partner" shall mean Steven R. Williams or any
successor to his interest.
(v) "Investor Partner" shall mean any Person other than the Managing
General Partner (i) whose name is set forth on Exhibit A, attached hereto,
as an Additional General Partner or as a Limited Partner, or who has been
admitted as an additional or Substituted Investor Partner pursuant to the
terms of this Agreement, and (ii) who is the owner of a Unit. "Investor
Partners" means all such Persons. All references in this Agreement to a
majority in interest or a specified percentage of the Investor Partners
shall mean Investor Partners holding more than 50% or such specified
percentage, respectively, of the outstanding Units then held.
(w) "Lease" shall mean full or partial interests in: (i) undeveloped
oil and gas leases; (ii) oil and gas mineral rights; (iii) licenses; (iv)
concessions; (v) contracts; (vi) fee rights; or (vii) other rights
authorizing the owner thereof to drill for, reduce to possession and
produce oil and gas.
(x) "Limited Partner" shall mean an Investor Partner who purchases Units
as a Limited Partner, such partner's transferees or assignees, and an
Additional General Partner who converts his interest to a limited
partnership interest pursuant to the provisions of the Agreement.
"Limited Partners" shall mean all such Investor Partners.
(y) "Management Fee" shall mean that fee to which the Managing General
Partner is entitled pursuant to Section 6.06 hereof.
(z) "Managing General Partner" shall mean Petroleum Development
Corporation or its successors, in their capacity as the Managing General
Partner.
(aa) "Mcf" shall mean one thousand cubic feet of natural gas.
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(bb) "Net Subscriptions" shall mean an amount equal to the total
Subscriptions of the Investor Partners less the amount of Organization and
Offering Costs of the Partnership.
(cc) "Nonrecourse Deductions" shall have the meaning set forth in
Treas. Reg. Section 1.704-2(b)(1). The amount of Nonrecourse Deductions
for a Partnership fiscal year shall equal the net increase in the amount
of Partnership Minimum Gain during that fiscal year reduced (but not below
zero) by the aggregate distributions during that fiscal year of proceeds
of a Nonrecourse Liability that are allocable to an increase in
Partnership Minimum Gain, determined according to the provisions of Treas.
Reg. Section 1.704-2(c).
(dd) "Nonrecourse Liability" shall have the meaning set forth in
Treas. Reg. Sections 1.704-2(b)(3) and 1.752-1(a)(2).
(ee) "Offering Termination Date" shall mean December 31, 1996 with
respect to Partnerships designated "PDC 1996-_ Limited Partnership
(December 31, 1997 with respect to Partnerships designated "PDC 1997-_
Limited Partnership") or such earlier date as the Managing General
Partner, in its sole and absolute discretion, shall elect.
(ff) "Oil and Gas Interest" shall mean any oil or gas royalty or lease,
or fractional interest therein, or certificate of interest or
participation or investment contract relative to such royalties, leases or
fractional interests, or any other interest or right which permits the
exploration of, drilling for, or production of oil and gas or other
related hydrocarbons or the receipt of such production or the proceeds
thereof.
(gg) "Operating Costs" shall mean expenditures made and costs incurred
in producing and marketing oil or gas from completed wells, including, in
addition to labor, fuel, repairs, hauling, materials, supplies, utility
charges and other costs incident to or therefrom, ad valorem and severance
taxes, insurance and casualty loss expense, and compensation to well
operators or others for services rendered in conducting such operations.
(hh) "Organization and Offering Costs" shall mean all costs of
organizing and selling the offering including, but not limited to, total
underwriting and brokerage discounts and commissions (including fees of
the underwriters' attorneys), expenses for printing, engraving, mailing,
salaries of employees while engaged in sales activity, charges of transfer
agents, registrars, trustees, escrow holders, depositaries, engineers and
other experts, expenses of qualification of the sale of the securities
under Federal and State law, including taxes and fees, accountants' and
attorneys' fees and other frontend fees.
(ii) "Overriding Royalty Interest" shall mean an interest in the oil
and gas produced pursuant to a specified oil and gas lease or leases, or
the proceeds from the sale thereof, carved out of the working interest, to
be received free and clear of all costs of development, operation, or
maintenance.
(jj) "Partner Minimum Gain" shall mean an amount, with respect to each
Partner Nonrecourse Debt, equal to the Partnership Minimum Gain that would
result if such Partner Nonrecourse Debt were treated as a Nonrecourse
Liability, determined in accordance with Treas. Reg. Section 1.704-2(i).
(kk) "Partner Nonrecourse Debt" shall have the meaning set forth in
Treas. Reg. Section 1.704-2(b)(4).
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(ll) "Partner Nonrecourse Deductions" shall have the meaning set forth
in Treas. Reg. Section 1.704-2(i)(2). The amount of Partner Nonrecourse
Deductions with respect to a Partner Nonrecourse Debt for a Partnership
fiscal year shall equal the net increase in the amount of Partner Minimum
Gain attributable to such Partner Nonrecourse Debt during that fiscal year
reduced (but not below zero) by proceeds of the liability distributed
during that fiscal year to the Partner bearing the economic risk of loss
for such liability that are both attributable to the liability and
allocable to an increase in Partner Minimum Gain attributable to such
Partner Nonrecourse Debt, determined in accordance with Treas. Reg.
Section 1.704-2(i)(3).
(mm) "Partners" shall mean the Managing General Partner, the Initial
Limited Partner, and the Investor Partners. "Partner" shall mean any one
of the Partners. All references in this Agreement to a majority in
interest or a specified percentage of the Partners shall mean Partners
holding more than 50% or such specified percentage, respectively, of the
outstanding Units then held.
(nn) "Partnership" shall mean the partnership pursuant to this
Agreement and the partnership continuing the business of this Partnership
in the event of dissolution as herein provided.
(oo) "Partnership Minimum Gain" shall have the meaning set forth in
Treas. Reg. Sections 1.704-2(b)(2) and 1.704-2(d)(1).
(pp) "Permitted Transfer" shall mean any transfer of Units satisfying
the provisions of Section 7.03 herein.
(qq) "Person" shall mean any individual, partnership, corporation,
trust, or other entity.
(rr) "Profits" and "Losses" shall mean, for each fiscal year or other
period, an amount equal to the Partnership's taxable income or loss for
such year or period, determined in accordance with Code Section 703(a)
(for this purpose, all items of income, gain, loss, or deduction required
to be stated separately pursuant to Code Section 703(a)(1) shall be
included in taxable income or loss), with the following adjustments:
(1) Any income of the Partnership that is exempt from federal
income tax and not otherwise taken into account in
computing Profits or Losses pursuant to this Section
1.08(rr) shall be added to such taxable income or loss;
(2) Any expenditures of the Partnership described in Code
Section 705(a)(2)(B) or treated as Code Section 705(a)
(2)(B) expenditures pursuant to Treas. Reg. Section 1.704-
1(b)(2)(iv)(i), and not otherwise taken into account in
computing Profits or Losses pursuant to this Section
1.08(rr) shall be subtracted from such taxable income or
loss;
(3) In the event the Gross Asset Value of any Partnership
asset is adjusted pursuant to Section 1.08(r)(2) or Section
1.08(r)(3) hereof, the amount of such adjustment shall
be taken into account as gain or loss from the
disposition of such asset for purposes of computing
Profits or Losses.
(4) Gain or loss resulting from any disposition of Partnership
Property with respect to which gain or loss is recognized
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for federal income tax purposes shall be computed by
reference to the Gross Asset Value of the property
disposed of, notwithstanding that the adjusted tax
basis of such property differs from its Gross Asset Value;
(5) In lieu of the depreciation, amortization, and other cost
recovery deductions taken into account in computing such
taxable income or loss, there shall be taken into account
Depreciation for such fiscal year or other period, computed
in accordance with Section 1.08(r) hereof; and
(6) Notwithstanding any other provisions of this Section
1.08(rr), any items which are specially allocated
pursuant to this Agreement shall not be taken into
account in computing Profits or Losses.
(ss) "Prospect" shall mean a contiguous oil and gas leasehold estate,
or lesser interest therein, upon which drilling operations may be
conducted. In general, a Prospect is an area in which the Partnership
owns or intends to own one or more oil and gas interests, which is
geographically defined on the basis of geological data by the Managing
General Partner of such Partnership and which is reasonably anticipated by
the Managing General Partner to contain at least one reservoir. An area
covering lands which are believed by the Managing General Partner to
contain subsurface structural or stratigraphic conditions making it
susceptible to the accumulations of hydrocarbons in commercially
productive quantities at one or more horizons. The area, which may be
different for different horizons, shall be designated by the Managing
General Partner in writing prior to the conduct of program operations and
shall be enlarged or contracted from time to time on the basis of
subsequently acquired information to define the anticipated limits of the
associated hydrocarbon reserves and to include all acreage encompassed
therein. A "prospect" with respect to a particular horizon may be limited
to the minimum area permitted by state law or local practice, whichever is
applicable, to protect against drainage from adjacent wells if the well to
be drilled by the Partnership is to a horizon containing proved reserves.
(tt) "Prospectus" shall mean that Prospectus (including any
preliminary prospectus), of which this Agreement is a part, pursuant to
which the Units are being offered and sold.
(uu) "Proved Developed Oil and Gas Reserves shall mean the reserves
that can be expected to be recovered through existing wells with existing
equipment and operating methods. Additional oil and gas expected to be
obtained through the application of fluid injection or other improved
recovery techniques for supplementing the natural forces and mechanisms of
primary recovery should be included as "proved developed reserves" only
after testing by a pilot project or after the operation of an installed
program has confirmed through production response that increased recovery
will be achieved.
(vv) "Proved Oil and Gas Reserves" shall mean the estimated quantities
of crude oil, natural gas, and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be recoverable
in future years from known reservoirs under existing economic and
operating conditions, i.e., prices and costs as of the date the estimate
is made. Prices include consideration of changes in existing prices
provided only by contractual arrangements, but not on escalations based
upon future conditions.
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(1) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation
test. The area of a reservoir considered proved includes (A)
that portion delineated by drilling and defined by gas-oil
and/or oil-water contacts, if any, and (B) the immediately
adjoining portions not yet drilled, but which can be
reasonably judged as economically productive on the basis
of available geological and engineering data. In the
absence of information on fluid contacts, the lowest
known structural occurrence of hydrocarbons controls the
lower proved limit of the reservoir.
(2) Reserves which can be produced economically through
application of improved recovery techniques (such as fluid
injection) are included in the "proved" classification when
successful testing by a pilot project, or the operation of an
installed program in the reservoir, provides support for the
engineering analysis on which the project or program was
based.
(3) Estimates or proved reserves do not include the following:
(A) oil that may become available from known reservoirs
but is classified separately as "indicated additional
reserves; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir
characteristics, or economic factors; (C) crude oil,
natural gas, and natural gas liquids, that may
occur in undrilled prospects; and (D) crude oil, natural
gas, and natural gas liquids, that may be recovered from oil
shales, coal, gilsonite and other such sources.
(ww) "Proved Undeveloped Reserves" shall mean the reserves that are
expected to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required for
recompletion. Reserves on undrilled acreage shall be limited to those
drilling units offsetting productive units that are reasonably certain of
production when drilled. Proved reserves for other undrilled units can be
claimed only where it can be demonstrated with certainty that there is
continuity of production from the existing productive formation. Under no
circumstances should estimates for proved undeveloped reserves be
attributable to any acreage for which an application of fluid injection or
other improved recovery technique is contemplated, unless such techniques
have been proved effective by actual tests in the area and in the same
reservoir.
(xx) "Reservoir" shall mean a separate structural or stratigraphic
trap containing an accumulation of oil or gas.
(yy) "Roll-Up" shall mean a transaction involving the acquisition,
merger, conversion, or consolidation, either directly or indirectly, of
the Partnership and the issuance of securities of a roll-up entity. Such
term does not include:
(1) a transaction involving securities of the Partnership that
have been listed for at least 12 months on a national
exchange or traded through the National Association of
Securities Dealers Automated Quotation National Market
System; or
(2) a transaction involving the conversion to corporate, trust
or
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association form of only the Partnership if, as a
consequence of the transaction, there will be no
significant adverse change in any of the following:
(i) voting rights;
(ii) the term of existence of the Partnership;
(iii) sponsor compensation; or
(iv) the Partnership's investment objectives.
(zz) "Roll-Up Entity" shall mean a partnership, trust, corporation or
other entity that would be created or survive after the successful
completion of a proposed roll-up transaction.
(aaa) "Sponsor" shall mean any person directly or indirectly
instrumental in organizing, wholly or in part, a program or any person who
will manage or is entitled to manage or participate in the management or
control of a program. "Sponsor" includes the managing and controlling
general partner(s) and any other person who actually controls or selects
the person who controls 25% or more of the exploratory, developmental or
producing activities of the Partnership, or any segment thereof, even if
that person has not entered into a contract at the time of formation of
the Partnership. "Sponsor" does not include wholly independent third
parties such as attorneys, accountants, and underwriters whose only
compensation is for professional services rendered in connection with the
offering of units. Whenever the context of these guidelines so requires,
the term "sponsor" shall be deemed to include its affiliates.
(bbb) "Subscription" shall mean the amount indicated on the
Subscription Agreement that an Investor Partner has agreed to pay to the
Partnership as his Capital Contribution.
(ccc) "Subscription Agreement" shall mean the Agreement, attached to
the Prospectus as Appendix B, pursuant to which an Investor subscribes to
Units in the Partnership.
(ddd) "Substituted Investor Partner" shall mean any Person admitted to
the Partnership as an Investor Partner pursuant to Section 7.03(c) hereof.
(eee) "Treas. Reg." or "Regulation" shall mean the income tax
regulations promulgated under the Code, as such regulations may be amended
from time to time (including corresponding provisions of succeeding
regulations).
(fff) "Unit" shall mean an undivided interest of the Investor Partners
in the aggregate interest in the capital and profits of the Partnership.
Each Unit represents Capital Contributions of $20,000 to the Partnership.
(ggg) "Working Interest" shall mean an interest in an oil and gas
leasehold which is subject to some portion of the costs of development,
operation, or maintenance.
ARTICLE II
Capitalization
2.01 Capital Contributions of the Managing General Partner and Initial
Limited Partner.
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(a) On or before the Offering Termination Date, the Managing
General Partner shall make a Capital Contribution in cash to the
Partnership of an amount equal to not less than 21-7/8% of the aggregate
Capital Contributions of the Investor Partners. The Managing General
Partner shall pay all Lease and tangible drilling costs as well as all
Intangible Drilling Costs in excess of such costs paid by the Investor
Partners with respect to the Partnership; to the extent that such costs
are greater than the Managing General Partner's Capital Contribution set
forth in the previous sentence, the Managing General Partner shall make
such additional contributions in cash to the Partnership equal to such
additional Costs. In consideration of making such Capital Contribution,
becoming a General Partner, subjecting its assets to the liabilities of
the Partnership, and undertaking other obligations as herein set forth,
the Managing General Partner shall receive the interest in the
Partnership allocated in Article III hereof.
(b) The Initial Limited Partner shall contribute $100 in cash to
the capital of the Partnership. Upon the earlier of the conversion of
an Additional General Partner's interest into a Limited Partner's
interest or the admission of a Limited Partner to the Partnership, the
Partnership shall redeem in full, without interest or deduction, the
Initial Limited Partner's Capital Contribution, and the Initial Limited
Partner shall cease to be a Partner.
2.02 Capital Contributions of the Investor Partners.
(a) Upon execution of this Agreement, each Investor Partner (whose
names and addresses and number of Units to which Subscribed are set
forth in Exhibit A) shall contribute to the capital of the Partnership
the sum of $20,000 for each Unit purchased. The minimum subscription
by an Investor Partner is one-quarter Unit ($5,000). The maximum
aggregate number of Units which may be purchased by Investor Partners
is two thousand five hundred (2,500).
(b) The contributions of the Investor Partners pursuant to
subsection 2.02(a) hereof shall be in cash or by check subject to
collection.
(c) Until the Offering Termination Date and until such
subsequent time as the contributions of the Investor Partners are
invested in accordance with the provisions of the Prospectus, all monies
received from persons subscribing as Investor Partners (i) shall continue
to be the property of the investor making such payment, (ii) shall be
held in escrow for such investor in the manner and to the extent provided
in the Prospectus, and (iii) shall not be commingled with the personal
monies or become an asset of the Managing General Partner or the
Partnership.
(d) Upon the original sale of Units by the Partnership,
subscribers shall be admitted as Partners no later than 15 days after
the release from the escrow account of the Capital Contributions to the
Partnership, in accordance with the terms of the Prospectus;
subscriptions shall be accepted or rejected by the Partnership within
30 days of their receipt; if rejected, all subscription monies shall be
returned to the subscriber forthwith.
(e) Except as provided in Section 4.03 hereof, any proceeds of the
offering of Units for sale pursuant to the Prospectus not used,
committed for use, or reserved as operating capital in the Partnership's
operations within one year after the closing of such offering shall be
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distributed pro rata to the Investor Partners as a return of capital and
the Managing General Partner shall reimburse such Investors for selling
expenses, management fees, and offering expenses allocable to the return
of capital.
(f) Until proceeds from the public offering are invested in the
Partnership's operations, such proceeds may be temporarily invested in
income producing short-term, highly liquid investments, where there is
appropriate safety of principal, such as U.S. Treasury Bills. Any such
income shall be allocated pro rata to the Investor Partners providing
such capital contributions.
2.03 Additional Contributions. Except as otherwise provided in this
Agreement, no Investor Partner shall be required or obligated (a) to
contribute any capital to the Partnership other than as provided in
Section 2.02 hereof, or (b) to lend any funds to the Partnership. No
interest shall be paid on any capital contributed to the Partnership
pursuant to this Article II and, except as otherwise provided herein, no
Partner, other than the Initial Limited Partner as authorized herein, may
withdraw his Capital Contribution. The Units are nonassessable; however,
General Partners are liable, in addition to their Capital Contributions,
for Partnership obligations and liabilities represented by their ownership
of interests as general partners, in accordance with West Virginia law.
ARTICLE III
Capital Accounts and Allocations
3.01 Capital Accounts.
(a) General. A separate Capital Account shall be established
and maintained for each Partner on the books and records of the
Partnership. Capital Accounts shall be maintained in accordance with
Treas. Reg. Section 1.704-1(b) and any inconsistency between the
provisions of this Section 3.01 and such regulation shall be resolved
in favor of the regulation. In the event the Managing General Partner
shall determine that it is prudent to modify the manner in which the
Capital Accounts, or any debits or credits thereto (including, without
limitation, debits or credits relating to liabilities that are secured
by contributed or distributed property or that are assumed by the
Partnership of the Partners), are computed in order to comply with such
regulations, the Managing General Partner may make such modification,
provided that it is not likely to have a material effect on the amounts
distributable to any Partner pursuant to Section 9.03 hereof upon the
dissolution of the Partnership. The Managing General Partner also shall
(i) make any adjustments that are necessary or appropriate to maintain
equality between the Capital Accounts of the Partners and the amount of
Partnership capital reflected on the Partnership's balance sheet, as
computed for book purposes, in accordance with Treas. Reg.
Section 1.704-1(b)(2)(iv)(q), and (ii) make any appropriate
modifications in the event unanticipated events might otherwise cause
this Agreement not to comply with Treas. Reg. Section 1.704-1(b).
(b) Increases to Capital Accounts. Each Partner's Capital Account
shall be credited with (i) the amount of money contributed by him to the
Partnership; (ii) the amount of any Partnership liabilities that are
assumed by him (within the meaning of Treas. Reg. Section 1.704-
1(b)(2)(iv)(c)), but not by increases in his share of Partnership
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liabilities within the meaning of Code Section 752(a); (iii) the Gross
Asset Value of property contributed by him to the Partnership (net of
liabilities securing such contributed property that the Partnership is
considered to assume or take subject to under Code Section 752); and
(iv) allocations to him of Partnership Profits (or items thereof),
including income and gain exempt from tax and Income and gain described
in Treas. Reg. Section 1.704-1(b)(2)(iv)(g) (relating to adjustments to
reflect book value).
(c) Decreases to Capital Accounts. Each Partner's Capital Account
shall be debited with (i) the amount of money distributed to him by the
Partnership; (ii) the amount of his individual liabilities that are
assumed by the Partnership (other than liabilities described in Treas.
Reg. Section 1.704-1(b)(2)(iv)(b)(2) that are assumed by the Partnership
and other than decreases in his share of Partnership liabilities within
the meaning of Code Section 752(b)); (iii) the Gross Asset Value of
property distributed to him by the Partnership (net of liabilities
securing such distributed property that he is considered to assume or
take subject to under Code Section 752); (iv) allocations to him of
expenditures of the Partnership not deductible in computing Partnership
taxable income and not properly chargeable to Capital Account (as
described in Code Section 705(a)(2)(B)), and (v) allocations to him of
Partnership Losses (or item thereof), including loss and deduction
described in Treas. Reg. Section 1.704-1(b)(2)(iv)(g) (relating to
adjustments to reflect book value), but excluding items described in
(iv) above and excluding loss or deduction described in Treas. Reg.
Section 1.704-1(b)(4)(iii) (relating to excess percentage depletion).
(d) Adjustments to Capital Accounts Related to Depletion.
(i) Solely for purposes of maintaining the Capital Accounts,
each year the Partnership shall compute (in accordance with Treas.
Reg. Section 1.704-1(b)(2)(iv)(k)) a simulated depletion allowance
for each oil and gas property using that method, as between the
cost depletion method and the percentage depletion method (without
regard to the limitations of Code Section 613A(c)(3) which
theoretically could apply to any Partner), which results in the
greatest simulated depletion allowance. The simulated depletion
allowance with respect to each oil and gas property shall reduce
the Partners' Capital Accounts in the same proportion as the
Partners were allocated adjusted basis with respect to such oil and
gas property under Section 3.03(a) hereof. In no event shall the
Partnership's aggregate simulated depletion allowance with respect
to an oil and gas property exceed the Partnership's adjusted basis
in the oil and gas property (maintained solely for Capital Account
purposes).
(ii) Upon the taxable disposition of an oil and gas property by
the Partnership, the Partnership shall determine the simulated
(hypothetical) gain or loss with respect to such oil and gas
property (solely for Capital Account purposes) by subtracting the
Partnership's simulated adjusted basis for the oil and gas property
(maintained solely for Capital Account purposes) from the amount
realized by the Partnership upon such disposition. Simulated
adjusted basis shall be determined by reducing the adjusted basis
by the aggregate simulated depletion charged to the Capital
Accounts of all Partners in accordance with Section 3.01(d)(i)
hereof. The Capital Accounts of the Partners shall be adjusted
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upward by the amount of any simulated gain on such disposition in
proportion to such Partners' allocable share of the portion of
total amount realized from the disposition of such property that
exceeds the Partnership's simulated adjusted basis in such
property. The Capital Accounts of the Partners shall be adjusted
downward by the amount of any simulated loss in proportion to such
Partners' allocable shares of the total amount realized from the
disposition of such property that represents recovery of the
Partnership's simulated adjusted basis in such property.
(e) Restoration of Negative Capital Accounts. Except as otherwise
provided in this Agreement, neither an Investor Partner nor the Initial
Limited Partner shall be obligated to the Partnership or to any other
Partner to restore any negative balance in his Capital Account. The
Managing General Partner shall be obligated to restore the deficit
balance in its Capital Account.
3.02 Allocation of Profits and Losses.
(a) General. Except as provided in this Section 3.02 or in
Section 3.03 hereof, Profits and Losses of the Partnership shall be
allocated 80% to the Investor Partners and 20% to the Managing General
Partner; provided, that if the subordination of the Managing General
Partner's share of cash distributions is effected pursuant to Section
4.02 the allocations of Profits and Losses of the Partnership shall be
allocated to reflect such subordination. Notwithstanding the above
allocations, the following special allocations shall be employed:
(i) IDC and recapture of IDC shall be allocated 100% to the
Investor Partners and 0% to the Managing General Partner;
(ii) Organization and Offering Costs net of commissions, due
diligence expenses and wholesaling fees payable to the dealer
manager and the soliciting dealers shall be paid by the Managing
General Partner; such commissions, due diligence expenses and
wholesaling fees payable to the dealer manager and the soliciting
dealers shall be allocated 100% to the Investor Partners and 0% to
the Managing General Partner; except that Organization and Offering
Costs in excess of 10 1/2% of Subscriptions shall be allocated 100%
to the Managing General Partner and 0% to the Investor Partners;
(iii) the Management Fee shall be allocated 100% to the Investor
Partners and 0% to the Managing General Partner;
(iv) Costs of Leases and Costs of tangible equipment, including
depreciation or cost recovery benefits, and revenues from the sale
of equipment shall be allocated 0% to the Investor Partners and
100% to the Managing General Partner;
(v) Drilling and Completion Costs shall be allocated 80% to
the Investor Partners and 20% to the Managing General Partner;
(vi) Direct Costs and Operating Costs shall be allocated 80%
to the Investor Partners and 20% to the Managing General Partner;
and
(vii) Administrative Costs shall be borne 100% by and allocated
100% to the Managing General Partner.
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(b) Capital Account Deficits. Notwithstanding anything to the
contrary in Section 3.02(a), no Investor Partner shall be allocated any
item to the extent that such allocation would create or increase a
deficit in such Investor Partner's Capital Account.
(i) Obligations to Restore. For purposes of this Section
3.02(b), in determining whether an allocation would create or
increase a deficit in a Partner's Capital Account, such Capital
Account shall be reduced for those items described in Treas. Reg.
Sections 1.704-1(b)(2)(ii)(d)(4), (5), and (6) and shall be
increased by any amounts which such Partner is obligated to
restore or is deemed obligated to restore pursuant to the
penultimate sentences of Treas. Reg. Sections 1.704-2(g)(1) and
1.704-2(i)(5). Further, such Capital Accounts shall otherwise
meet the requirements of Treas. Reg. Section 1.704-1(b)(2)(ii)(d).
(ii) Reallocations. Any loss or deduction of the Partnership,
the allocation of which to any Partner is prohibited by this Section
3.02(b), shall be reallocated to those Partners not having a
deficit in their Capital Accounts (as adjusted in Section
3.02(b)(i)) in the proportion that the positive balance of each
such Partner's adjusted Capital Account bears to the aggregate
balance of all such Partners' adjusted Capital Accounts, with any
remaining losses or deductions being allocated to the Managing
General Partner.
(iii) Qualified Income Offset. In the event any Investor
Partner unexpectedly receives any adjustments, allocations, or
distributions described in Treas. Reg. Section 1.704-
1(b)(2)(ii)(d)(4), (5), or (6), items of Partnership income and
gain shall be specifically allocated to such Partner in an amount
and manner sufficient to eliminate (to the extent required by the
Regulations) the total of the deficit balance in his Capital
Account (as adjusted in Section 3.02(b)(i)) created by such
adjustments, allocations, or distributions, provided that an
allocation pursuant to this Section 3.02(b)(iii) shall be made if
and only to the extent that such Partner would have a deficit in
his Capital Account (as adjusted in Section 3.02(b)(i)) after all
other allocations provided for in this Section 3 have been
tentatively made as if this Section 3.02(b)(iii) were not in the
Agreement.
(iv) Gross Income Allocations. In the event an Investor
Partner has a deficit Capital Account at the end of any
Partnership fiscal year which is in excess of the sum of (i) the
amount such Partner is obligated to restore pursuant to any
provision of this Agreement and (ii) the amount such Partner is
deemed to be obligated to restore pursuant to the penultimate
sentences of Treas. Reg. Sections 1.704-2(g)(1) and 1.704-2(i)(5),
such Partner shall be specially allocated items of Partnership
income and gain in the amount of such excess as quickly as
possible, provided that an allocation pursuant to this Section
3.02(b)(iv) shall be made only if and to the extent that such
Partner would have a deficit Capital Account in excess of such
sum after all other allocations provided for in this Section 3
have been made as if Section 3.02(b)(iii) hereof and this Section
3.02(b)(iv) were not in the Agreement.
(c) Minimum Gain Chargeback. Notwithstanding any other
provision of this Section 3.02, if there is a net decrease in Partnership
Minimum Gain during any taxable year, pursuant to Treas. Reg. Section 1.704-
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2(f)(1), all Partners shall be allocated items of partnership income and
gain for that year equal to that partner's share of the net decrease in
Partnership Minimum Gain (within the meaning of Treas. Reg.
Section 1.704-2(g)(2)). Notwithstanding the preceding sentence, no such
chargeback shall be made to the extent one or more of the exceptions
and/or waivers provided for in Treas. Reg. Section 1.704-2(f)(2)-(5)
applies. Allocations pursuant to the previous sentence shall be made
in proportion to the respective amounts required to be allocated to each
Partner pursuant thereto. The items to be so allocated shall be
determined in accordance with Treas. Reg. Section 1.704-2(f)(6). This
Section 3.02(c) is intended to comply with the minimum gain chargeback
requirement in such Section of the Regulations and shall be interpreted
consistently therewith. To the extent permitted by such Section of the
Regulations and for purposes of this Section 3.02(c) only, each
Partner's Capital Account (as adjusted in Section 3.02(b)(i)) shall be
determined prior to any other allocations pursuant to this Section 3
with respect to such tax year and without regard to any net decrease in
Partner Minimum Gain during such fiscal year.
(d) Partner Minimum Gain Chargeback. Notwithstanding any other
provision of this Section 3 except Section 3.02(c), if there is a net
decrease in Partner Minimum Gain attributable to a Partner Nonrecourse
Debt during any Partnership fiscal year, rules similar to those
contained in Section 3.02(c) shall apply in a manner consistent with
Treas. Reg. Section 1.704-2(i)(4). This Section 3.02(d) is intended to
comply with the minimum gain chargeback requirement in such Section of
the Regulations and shall be interpreted consistently therewith. Solely
for purposes of this Section 3.02(d), each Person's Capital Account
deficit (as so adjusted) shall be determined prior to any other
allocations pursuant to this Section 3 with respect to such fiscal year,
other than allocations pursuant to Section 3.02(c) hereof.
(e) Nonrecourse Deductions. Nonrecourse Deductions for any
fiscal year or other period shall be specially allocated to the Partners
(in proportion to their Units), in accordance with Treas. Reg.
Section 1.704-2.
(f) Partner Nonrecourse Deductions. Any Partner Nonrecourse
Deductions for any fiscal year or other period shall be specially
allocated to the Partner who bears the economic risk of loss with
respect to the Partner Nonrecourse Debt to which such Partner
Nonrecourse Deductions are attributable in accordance with Treas. Reg.
Section 1.704-2(i).
(g) Code Section 754 Adjustments. To the extent an adjustment to
the adjusted tax basis of any Partnership asset pursuant to Code
Section 734(b) or Section 743(b) is required, pursuant to Treas. Reg.
Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining
Capital Accounts, the amount of such adjustment to the Capital Accounts
shall be treated as an item of gain (if the adjustment increases the
basis of the asset) or loss (if the adjustment decreases such basis) and
such gain or loss shall be specially allocated to the Partners in a
manner consistent with the manner in which their Capital Accounts are
required to be adjusted pursuant to such Section of the Regulations.
(h) Curative Allocations.
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(i) The "Regulatory Allocations" consist of the "Basic
Regulatory Allocations," as defined in Section 3.02(h)(ii)
hereof, the "Nonrecourse Regulatory Allocations," as defined
in Section 3.02(h)(iii) hereof, and the "Partner Nonrecourse
Regulatory Allocations," as defined in Section 3.02(h)(iv)
hereof.
(ii) The "Basic Regulatory Allocations" consist of allocations
pursuant to Section 3.02(b)(ii), (iii), and (iv) hereof.
Notwithstanding any other provision of this Agreement, other than
the Regulatory Allocations, the Basic Regulatory Allocations shall
be taken into account in allocating items of income, gain, loss,
and deduction among the Partners so that, to the extent possible,
the net amount of such allocations of other items and the Basic
Regulatory Allocations to each Partner shall be equal to the net
amount that would have been allocated to each such Partner if the
Basic Regulatory Allocations had not occurred. For purposes of
applying the foregoing sentence, allocations pursuant to this
Section 3.02(h)(ii) shall only be made with respect to allocations
pursuant to Section 3.02(g) hereof to the extent the Managing
General Partner reasonably determines that such allocations will
otherwise be inconsistent with the economic agreement among the
parties to this Agreement.
(iii) The "Nonrecourse Regulatory Allocations" consist of all
allocations pursuant to Section 3.02(c) and 3.02(e) hereof.
Notwithstanding any other provision of this Agreement, other than
the Regulatory Allocations, the Nonrecourse Regulatory Allocations
shall be taken into account in allocating items of income, gain,
loss, and deduction among the Partners so that, to the extent
possible, the net amount of such allocations of other items and the
Nonrecourse Regulatory Allocations to each Partner shall be equal
to the net amount that would have been allocated to each Partner if
the Nonrecourse Regulatory Allocations had not occurred. For
purposes of applying the foregoing sentence (i) no allocations
pursuant to this Section 3.02(h)(iii) shall be made prior to the
Partnership fiscal year during which there is a net decrease in
Partnership Minimum Gain, and then only to the extent necessary to
avoid any potential economic distortions caused by such net
decrease in Partnership Minimum Gain, and (ii) allocations pursuant
to this Section 3.02(h)(iii) shall be deferred with respect to
allocations pursuant to Section 3.02(e) hereof to the extent the
Managing General Partner reasonably determines that such
allocations are likely to be offset by subsequent allocations
pursuant to Section 3.02(c).
(iv) The "Partner Nonrecourse Regulatory Allocations" consist
of all allocations pursuant to Sections 3.02(d) and 3.02(f) hereof.
Notwithstanding any other provision of this Agreement, other than
the Regulatory Allocations, the Partner Nonrecourse Regulatory
Allocations shall be taken into account in allocating items of
income, gain, loss, and deduction among the Partners so that, to
the extent possible, the net amount of such allocations of other
items and the Partner Nonrecourse Regulatory Allocations to each
Partner shall be equal to the net amount that would have been
allocated to each such Partner if the Partner Nonrecourse
Regulatory Allocations had not occurred. For purposes of applying
the foregoing sentence (i) no allocations pursuant to this Section
3.02(h)(iv) shall be made with respect to allocations pursuant to
Section 3.02(f) relating to a particular Partner Nonrecourse Debt
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prior to the Partnership fiscal year during which there is a net
decrease in Partner Minimum Gain attributable to such Partner
Nonrecourse Debt, and then only to the extent necessary to avoid
any potential economic distortions caused by such net decrease in
Partner Minimum Gain, and (ii) allocations pursuant to this Section
3.02(h)(iv) shall be deferred with respect to allocations pursuant
to Section 3.02(f) hereof relating to a particular Partner
Nonrecourse Debt to the extent the Managing General Partner
reasonably determines that such allocations are likely to be offset
by subsequent allocations pursuant to Section 3.02(d) hereof.
(v) The Managing General Partner shall have reasonable
discretion with respect to each Partnership fiscal year, to apply
the provisions of Sections 3.02(h)(ii), (iii), and (iv) hereof among
the Partners in a manner that is likely to minimize such economic
distortions.
(i) Other Allocations. Except as otherwise provided in this
Agreement, all items of Partnership income, loss, deduction, and any
other allocations not otherwise provided for shall be divided among the
Unit Holders in the same proportions as they share Profits or Losses,
as the case may be, for the year.
(j) Agreement to be Bound. The Partners are aware of the income
tax consequences of the allocations made by this Section 3.02 and hereby
agree to be bound by the provisions of this Section 3.02 in reporting
their shares of Partnership income and loss for income tax purposes.
(k) Excess Nonrecourse Liabilities. Solely for purposes of
determining a Partner's proportionate share of the "excess nonrecourse
liabilities" of the Partnership within the meaning of Treas. Reg.
Section 1.752-3(a)(3), the Partners' interests in Partnership profits
are as follows: Investor Partners, 80% (in proportion to their Units)
and the Managing General Partner, 20%.
(l) Allocation Variations. The Managing General Partner shall
have the authority to vary allocations to preserve and protect the
intention of the Partners as follows:
(i) It is the intention of the Partners that each Partner's
distributive share of income, gain, loss, deduction or credit (or
any item thereof) shall be determined and allocated in accordance
with this Article 3 to the fullest extent permitted by Code
Section 704(b). In order to preserve and protect the allocations
provided for in this Article 3, the Managing General Partner shall
have the authority to allocate income, gain, loss, deduction or
credit (or any item thereof) arising in any year differently than
that expressly provided for in this Article 3, if and to the extent
that determining and allocating income, gain, loss, deduction or
credit (or any item thereof) in the manner expressly provided for
in this Article 3 would cause the allocations of each Partner's
distributive share of income, gain, loss, deduction or credit (or
any item thereof) not to be permitted by Code Section 704(b) and
the Regulations promulgated thereunder. Any allocation made
pursuant to this Section 3.02(l) shall be deemed to be a complete
substitute for any allocation otherwise expressly provided for in
this Article 3, and no amendment of this Agreement or further
consent of any Partner shall be required therefor.
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(ii) In making any such allocation (the "new allocation")
under this Section 3.02(l) the Managing General Partner shall be
authorized to act only after having been advised by the
Partnership's accountants and/or counsel that, under Code
Section 704(b) and the Regulations thereunder, (i) the new
allocation is necessary, and (ii) the new allocation is the minimum
modification of the allocations otherwise expressly provided for in
this Article 3 which is necessary in order to assure that, either
in the then current year or in any preceding year, each Partner's
distributive share of income, gain, loss, deduction or credit (or
any item thereof) is determined and allocated in accordance with
this Article 3 to the fullest extent permitted by Code
Section 704(b) and the Regulations thereunder.
(iii) If the Managing General Partner is required by this
Section 3.02(l) to make any new allocation in a manner less
favorable to the Investor Partners than is otherwise expressly
provided for in this Article 3, then the Managing General Partner
shall have the authority, only after having been advised by the
Partnership's accountants and/or counsel that they are permitted
by Code Section 704(b), to allocate income, gain, loss, deduction
or credit (or any item thereof) arising in later years in such a
manner as will make the allocations of income, gain, loss,
deduction or credit (or any item thereof) to the Investor
Partners as comparable as possible to the allocations otherwise
expressly provided for or contemplated by this Article 3.
(iv) Any new allocation made by the Managing General Partner
under this Section 3.02(l) in reliance upon the advice of the
Partnership's accountants and/or counsel shall be deemed to be made
pursuant to the fiduciary obligation of the Managing General
Partner to the Partnership and the Investor Partners, and no such
new allocation shall give rise to any claim or cause of action by
any Investor Partner.
(m) Tax Allocations: Code Section 704(c). In accordance with Code
Section 704(c) and the Regulations thereunder, income, gain, loss, and
deduction with respect to any property contributed to the capital of the
Partnership shall, solely for tax purposes, be allocated among the
Partners so as to take account of any variation between the adjusted basis
of such property to the Partnership for federal income tax purposes and
its initial Gross Asset Value (computed in accordance with Section
1.08(r)(1).
In the event the Gross Asset Value of any Partnership asset is adjusted
pursuant to Section 1.08(r)(1) hereof, subsequent allocations of income,
gain, loss, and deduction with respect to such asset shall take account of
any variation between the adjusted basis of such asset for federal income
tax purposes and its Gross Asset Value in the same manner as under Code
Section 704(c) and the Regulations thereunder.
Any elections or other decisions relating to such allocations shall be
made by the Managing General Partner in any manner that reasonably
reflects the purpose and intention of this Agreement. Allocations
pursuant to this Section 3.02(m) are solely for purposes of federal,
state, and local taxes and shall not affect, or in any way be taken into
account in computing, any Person's Capital Account or share of Profits,
Losses, other items, or distributions pursuant to any provision of this
Agreement.
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3.03 Depletion.
(a) The depletion deduction with respect to each oil and gas
property of the Partnership shall be computed separately for each
Partner in accordance with Code Section 613A(c)(7)(D) for Federal income
tax purposes. For purposes of such computation, the adjusted basis of
each oil and gas property shall be allocated in accordance with the
Partners' interests in the capital of the Partnership. Among the
Investor Partners, such adjusted basis shall be apportioned among them
in accordance with the number of Units held.
(b) Upon the taxable disposition of an oil or gas property by
the Partnership, the amount realized from and the adjusted basis of such
property shall be allocated among the Partners (for purposes of
calculating their individual gain or loss on such disposition for
Federal income tax purposes) as follows:
(i) The portion of the total amount realized upon the taxable
disposition of such property that represents recovery of its
simulated adjusted tax basis therein (as calculated pursuant to
Section 3.01(d) hereof) shall be allocated to the Partners in the
same proportion as the aggregate adjusted basis of such property
was allocated to such Partners (or their predecessors in interest)
pursuant to Section 3.03(a) hereof; and
(ii) The portion of the total amount realized upon the taxable
disposition of such property that represents the excess over the
simulated adjusted tax basis therein shall be allocated in
accordance with the provisions of Section 3.02 hereof as if such
gain constituted an item of Profit.
3.04 Apportionment Among Partners:
(a) Except as otherwise provided in this Agreement, all
allocations and distributions to the Investor Partners shall be
apportioned among them pro rata based on Units held by the Partners.
(b) For purposes of Section 3.04(a) hereof, an Investor
Partner's pro rata share in Units shall be calculated as of the end of
the taxable year for which such allocation has been made; provided,
however, that if a transferee of a Unit is admitted as an Investor
Partner during the course of the taxable year, the apportionment of
allocations and distributions between the transferor and transferee of
such Unit shall be made in the manner provided in Section 3.04(c) hereof.
(c) If, during any taxable year of the Partnership, there is a
change in any Partner's interest in the Partnership, each Partner's
allocation of any item of income, gain, loss, deduction, or credit of
the Partnership for such taxable year, other than "allocable cash basis
items" shall be determined by taking into account the varying interests
of the Partners pursuant to such method as is permitted by Code
Section 706(d) and the regulations thereunder. Each Partner's share of
"allocable cash basis items" shall be determined in accordance with Code
Section 706(d)(2) by (i) assigning the appropriate portion of each item
to each day in the period to which it is attributable, and (ii)
allocating the portion assigned to any such day among the Partners in
proportion to their interests in the Partnership at the close of such
day. "Allocable cash basis item" shall have the meaning ascribed to it
by Code Section 706(d)(2)(B) and the regulations thereunder.
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ARTICLE IV
Distributions
4.01 Time of Distribution. Cash available for distribution shall be
determined by the Managing General Partner. The Managing General Partner
shall distribute, in its discretion, such cash deemed available for
distribution, but such distributions shall be made not less frequently
than quarterly.
4.02 Distributions. Except as provided below, all distributions (other
than those made to wind up the Partnership in accordance with Section 9.03
hereof) shall be made 80% to the Investor Partners and 20% to the Managing
General Partner. If at any time during the initial five year period of
distributions form all Partnership wells that cumulative cash
distributions to the Investor Partners average less than 10% of their
Subscription on an annual basis, subsequent distributions shall be
adjusted to increase the Investor Partners' interest in distribution until
such time as the cumulative average return is 10% or the subordination
period expires. The Managing General Partner shall subordinate up to 50%
of its 20% share of Partnership cash distributions so that the Investor
Partners will receive increased cash distributions. The subordination
period shall commence upon the initial cash distribution of the
Partnership after all Partnership wells have been placed in production and
shall continue in successive twelve-month periods thereafter until the
fifth anniversary of the initial cash distribution whereupon the
subordination obligation shall terminate. The Partnership shall not
require that Investor Partners reinvest their share of cash available for
distribution in the Partnership. In no event shall funds be advanced or
borrowed for purposes of distributions, if the amount of such
distributions would exceed the Partnership's accrued and received revenues
for the previous four quarters, less paid and accrued operating costs with
respect to such revenues. The determination of such revenues and costs
shall be made in accordance with generally accepted accounting principles,
consistently applied. Cash distributions from the Partnership to the
Managing General Partner shall only be made in conjunction with
distributions to Investor Partners and only out of funds properly
allocated to the Managing General Partner's account.
4.03 Capital Account Deficits. No distributions shall be made to any
Investor Partner to the extent such distribution would create or increase
a deficit in such Partner's Capital Account (as adjusted in Section
3.02(b)(i)). Any distribution which is hereby prohibited shall be made to
those Partners not having a deficit in their Capital Accounts (as adjusted
in Section 3.02(b)(i)) in the proportion that the positive balance of each
such Partner's adjusted Capital Account bears to the aggregate balance of
all such Partners' adjusted Capital Accounts. Any cash available for
distribution remaining after reduction of all adjusted Capital Accounts to
zero shall be distributed to the Managing General Partner.
4.04 Liability Upon Receipt of Distributions.
(a) If a Partner has received a return of any part of his
Capital Contribution without violation of the Partnership Agreement or
the Act, he is liable to the Partnership for a period of one year
thereafter for the amount of such returned contribution, but only to
the extent necessary to discharge the Partnership's liabilities to
creditors who extended credit to the Partnership during the period
the Capital Contribution was held by the Partnership.
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(b) If a Partner has received a return of any part of his
Capital Contribution in violation of either the Partnership Agreement
or the Act, he is liable to the Partnership for a period of six years
thereafter for the amount of the Capital Contribution wrongfully
returned.
(c) A Partner receives a return of his Capital Contribution to
the extent that the distribution to him reduces his share of the fair
value of the net assets of the Partnership below the value, as set forth
in the records required to be kept by West Virginia law, of his Capital
Contribution which has not been distributed to him.
ARTICLE V
Activities
5.01 Management. The Managing General Partner shall conduct, direct,
and exercise full and exclusive control over all activities of the
Partnership. Investor Partners shall have no power over the conduct of
the affairs of the Partnership or otherwise commit or bind the Partnership
in any manner. The Managing General Partner shall manage the affairs of
the Partnership in a prudent and businesslike fashion and shall use its
best efforts to carry out the purposes and character of the business of
the Partnership.
5.02 Conduct of Operations.
(a)(i) The Managing General Partner shall establish a program of
operations for the Partnership which shall be in conformance with the
following policies: (x) no less than 89.5% of the Capital Contributions
net of Organization and Offering Costs and the Management Fee shall be
applied to drilling and completing Development Wells; (y) the
Partnership shall drill all of its wells in West Virginia, Ohio,
Pennsylvania, New York, and/or Kentucky and (z) the Prospects will be
acquired pursuant to an arrangement whereby the Partnership will acquire
between 51% and 100% of the Working Interest, subject to landowners'
royalty interests and the royalty interests payable to unaffiliated
third parties in varying amounts, provided that the weighted average for
all Prospects of the Partnership shall not exceed 16.125%. At its
discretion, the Partnership may purchase less than a 51% Working
Interest with respect to the first and last Prospects acquired.
(ii) The Investor Partners agree to participate in the
Partnership's program of operations as established by the Managing
General Partner; provided, that no well drilled to the point of setting
casing need be completed if, in the Managing General Partner's opinion,
such well is unlikely to be productive of oil or gas in quantities
sufficient to justify the expenditures required for well completion.
The Partnership may participate with others in the drilling of wells and
it may enter into joint ventures, partnerships, or other such
arrangements.
(b) All transactions between the Partnership and the Managing
General Partner or its Affiliates shall be on terms no less favorable
than those terms which could be obtained between the Partnership and
independent third parties dealing at arm's-length, subject to the
provisions of Section 5.07 hereof.
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(c) The Partnership shall not participate in any joint
operations on any co-owned Lease unless there has been acquired or
reserved on behalf of the Partnership the right to take in kind or
separately dispose of its proportionate share of the oil and gas produced
from such Lease exclusive of production which may be used in development and
production operations on the Lease and production unavoidably lost, and,
if the Managing General Partner is the operator of such Lease, the
Managing General Partner has entered into written agreements with every
other person or entity owning any working or operating interest
reserving to such person or entity a similar right to take in-kind,
unless, in the opinion of counsel to the Partnership, the failure to
reserve such right to take in-kind will not result in the Partnership
being treated as a member of an association taxable as a corporation for
Federal income tax purposes.
(d) The relationship of the Partnership and the Managing General
Partner (or any Affiliate retaining or acquiring an interest) as co-
owners in Leases, except to the extent superseded by an Operating
Agreement consistent with the preceding paragraph and except to the
extent inconsistent with this Partnership Agreement, shall be governed
by the AAPL Form 610 Model Operating Agreement-1982, with a provision
reserving the right to take production in-kind, naming the Managing
General Partner as operator and the Partnership as a nonoperator, and
with the accounting procedure to govern as the accounting procedures
under such Operating Agreements.
(e) The Managing General Partner is expected to act as the
operator of all Partnership wells, and the Managing General Partner may
designate such other persons as it deems appropriate to conduct the
actual drilling and producing operations of the Partnership.
(f) As operator of Partnership wells, the Managing General
Partner or its Affiliates shall receive per-well charges for each
producing well based on the Working Interest acquired by the Partnership.
These per-well charges shall be subject to annual adjustment beginning
January 1, 1998 [with respect to Partnerships designated as "PDC 1996-
Limited Partnership" and January 1, 1999 with respect to Partnerships
designated as "PDC 1997- Limited Partnership"] as provided in the
accounting procedures of the operating agreements.
(g) The Managing General Partner shall drill wells pursuant to
drilling contracts with the Partnership based upon competitive prices
and terms in the geographic area of operations, and to the extent that
such prices exceed its Costs, the Managing General Partner shall be
deemed to have received compensation.
(h) The Managing General Partner shall be reimbursed by the
Partnership for Direct Costs. The Managing General Partner shall not
be reimbursed for any Administrative Costs. All other expenses shall
be borne by the Partnership.
(i) The Managing General Partner and its Affiliates may enter
into other transactions (embodied in a written contract) with the
Partnership, such as providing services, supplies, and equipment, and
shall be entitled to compensation for such services at prices and on
terms that are competitive in the geographic area of operations.
(j) The Partnership shall make no loans to the Managing General
Partner or any Affiliate thereof.
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(k) Neither the Managing General Partner nor any Affiliate shall
loan any funds to the Partnership.
(l) The funds of the Partnership shall not be commingled with
the funds of any other Person.
(m) Notwithstanding any provision herein to the contrary, no
creditor shall receive, as a result of making any loan, a direct or
indirect interest in the profits, capital, or property of the
Partnership other than as a secured creditor.
(n) The Managing General Partner shall have a fiduciary
responsibility for the safekeeping and use of all funds and assets of
the Partnership, whether or not in the Managing General Partner's
possession or control, and shall not employ or permit another to employ
such funds or assets in any manner except for the exclusive benefit of
the Partnership.
5.03 Acquisition and Sale of Leases.
(a) To the extent the Partnership does not acquire a full
interest in a Lease from the Managing General Partner, the remainder of the
interest in such Lease may be held by the Managing General Partner which
may either retain and exploit it for its own account or sell or
otherwise dispose of all or a part of such remaining interest. Profits
from such exploitation and/or disposition shall be for the benefit of
the Managing General Partner to the exclusion of the Partnership. Any
Leases acquired by the Partnership from the Managing General Partner
shall be acquired only at the Managing General Partner's Cost, unless
the Managing General Partner shall have reason to believe that Cost is
in excess of the fair market value of such property, in which case the
price shall not exceed the fair market value. The Managing General
Partner shall obtain an appraisal from a qualified independent expert
with respect to sales of properties of the Managing General Partner and
its Affiliates to the Partnership. Neither the Managing General Partner
nor any Affiliate shall acquire or retain any carried, reversionary, or
Overriding Royalty Interest on the Lease interests acquired by the
Partnership, nor shall the Managing General Partner enter into any
farmout arrangements with respect to its retained interest, except as
provided in Section 5.05 hereof.
(b) The Partnership shall acquire only Leases reasonably
expected to meet the stated purposes of the Partnership. No Leases shall be
acquired for the purpose of a subsequent sale or farmout unless the
acquisition is made after a well has been drilled to a depth sufficient
to indicate that such an acquisition would be in the Partnership's best
interest.
(c) Neither the Managing General Partner nor its Affiliates,
except other partnerships sponsored by them, shall purchase any
productive properties from the Partnership.
5.04 Title to Leases.
(a) Record title to each Lease acquired by the Partnership may
be temporarily held in the name of the Managing General Partner, or in the
name of any nominee designated by the Managing General Partner, as agent
for the Partnership until a productive well is completed on a Lease.
Thereafter, record title to Leases shall be assigned to and placed in
the name of the Partnership.
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(b) The Managing General Partner shall take the necessary steps
in its best judgment to render title to the Leases to be assigned to the
Partnership acceptable for the purposes of the Partnership. No
operation shall be commenced on any Prospect acquired by the Partnership
unless the Managing General Partner is satisfied that the undertaking
of such operation would be in the best interest of Investor Partners and
the Partnership. The Managing General Partner shall be free, however,
to use its own best judgment in waiving title requirements and shall not
be liable to the Partnership or the Investor Partners for any mistakes
of judgment unless such mistakes were made in a manner not in accordance
with general industry standards in the geographic area and such mistakes
were not the result of negligence by the Managing General Partner; nor
shall the Managing General Partner or its Affiliates be deemed to be
making any warranties or representations, express or implied, as to the
validity or merchantability of the title to any Lease assigned to the
Partnership or the extent of the interest covered thereby.
5.05 Farmouts.
(a) No Partnership Lease shall be farmed out, sold, or
otherwise disposed of unless the Managing General Partner determines that
(i) the Partnership lacks sufficient funds to drill on such Lease and is
unable to obtain suitable financing, (ii) the Leases have been downgraded by
events occurring after assignment to the Partnership, (iii) drilling on
the Leases would result in an excessive concentration, of Partnership
funds creating, in the Managing General Partner's opinion, undue risk
to the Partnership, or (iv) the Managing General Partner, exercising the
standard of a prudent operator, determines that the farmout is in the
best interests of the Partnership.
(b) Farmouts between the Partnership and the Managing General
Partner or its Affiliates, including any other affiliated limited
partnership, shall be effected on terms deemed fair by the Managing
General Partner. The Managing General Partner, exercising the standard
of a prudent operator, shall determine that the farmout is in the best
interest of the Partnership and the terms of the farmout are consistent
with and, in any case, no less favorable to the Partnership than those
utilized in the geographic area of operations for similar arrangements.
The respective obligations and revenue sharing of all affiliated parties
to the transactions shall be substantially the same, and the
compensation arrangement or any other interest or right of either the
Managing General Partner or its Affiliates shall be substantially the
same in each participating partnership or, if different, shall be
reduced to reflect the lower compensation arrangement.
5.06 Release, Abandonment, and Sale or Exchange of Properties. Except
as provided elsewhere in this Article V and in Section 6.03, the Managing
General Partner shall have full power to dispose of the production and
other assets of the Partnership, including the power to determine which
Leases shall be released or permitted to terminate, those wells to be
abandoned, whether any Lease or well shall be sold or exchanged, and the
terms therefor. In the event the Managing General Partner sells,
transfers, or otherwise disposes of nonproducing property of the
Partnership, the sale, transfer, or disposition shall, to the extent
possible, be made at a price which is the higher of the fair market value
of the property on the date of the sale, transfer, or disposition or the
Cost of such property to the Partnership.
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5.07 Certain Transactions.
(a) Whenever the Managing General Partner or its Affiliates sell,
transfer, or assign an interest in a Prospect to the Partnership, they
shall assign to the Partnership an equal proportionate interest in each
of the Leases comprising the Prospect. If the Managing General Partner
or its Affiliates (except another affiliated partnership in which the
interest of the Managing General Partner or its Affiliates is identical
to or less than their interest in the Partnership) subsequently propose
to acquire an interest in a Prospect in which the Partnership possesses
an interest or in a Prospect abandoned by the Partnership within one
year preceding such proposed acquisition, the Managing General Partner
or its Affiliates shall offer an equivalent interest therein to the
Partnership; and, if funds, including borrowings, are not available to
the Partnership to enable it to consummate a purchase of an equivalent
interest in such property and pay the development costs thereof, neither
the Managing General Partner nor any of its Affiliates shall acquire
such interest or property. The term "abandoned" shall mean the
termination, either voluntarily or by operation of the Lease or
otherwise, of all of the Partnership's interest in the Prospect. These
limitations shall not apply after the lapse of five years from the date
of formation of the Partnership.
(b) The geological limits of a Prospect shall be enlarged or
contracted on the basis of subsequently acquired geological data that
further defines the productive limits of the underlying oil and/or gas
reservoir and shall include all of the acreage determined by such
subsequent data to be encompassed by such reservoir; further, where the
Managing General Partner or Affiliate owns a separate property interest
in such enlarged area, such interest shall be sold to the Partnership
if the activities of the Partnership were material in establishing the
existence of proved undeveloped reserves which are attributable to such
separate property interest; provided, however, that the Partnership
shall not be required to expend additional funds unless they are
available from the initial capitalization of the Partnership or if the
Managing General Partner believes it is prudent to borrow for the
purpose of acquiring such additional acreage.
(c) The Partnership shall not purchase properties from or sell
properties to any other affiliated partnership. This prohibition,
however, shall not apply to transactions among affiliated partnerships
by which property is transferred from one to another in exchange for the
transferee's obligation to conduct drilling activities on such property
or to joint ventures among such affiliated partnerships, provided that
the respective obligations and revenue sharing of all parties to the
transaction are substantially the same and the compensation arrangement
or any other interest or right of either the Managing General Partner
or its Affiliates is the same in each affiliated partnership, or, if
different, the aggregate compensation of the Managing General Partner
is reduced to reflect the lower compensation arrangement.
(d) During the existence of the Partnership, and before it has
ceased operations, neither the Managing General Partner nor any of its
Affiliates (excluding another partnership where the Managing General
Partner's or its Affiliates' interest in such partnership is identical
to or less than their interest in the Partnership) shall acquire,
retain, or drill for their own account any oil and gas interest in any
Prospect in which the Partnership possesses an interest, except for
transactions whereby the Managing General Partner or such Affiliate
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acquires or retains a proportionate Working Interest, the respective
obligations of the Managing General Partner or the Affiliate and the
Partnership are substantially the same after the sale of the interest
to the Partnership, and the Managing General Partner's or Affiliate's
interest in revenues does not exceed the amount proportionate to its
Working Interest.
(e) Any services, equipment, or supplies which the Managing
General Partner or an Affiliate furnishes to the Partnership shall be
furnished at the lesser of the Managing General Partner's or the
Affiliate's Cost or a competitive rate which could be obtained in the
geographical area of operations unless the Managing General Partner or
any Affiliate is engaged to a substantial extent, as an ordinary and
ongoing business, in providing such services, equipment, or supplies to
others in the industry, in which event, the services, supplies, or
equipment may be provided by such person to the Partnership at prices
competitive with those charged by others in the geographical area of
operations which would be available to the Partnership. If such entity
is not engaged in the business as set forth above, then such
compensation, price or rental shall be the cost of such services,
equipment or supplies to such entity, or the competitive rate which
could be obtained in the area, whichever is less. Any drilling services
provided by the Managing General Partner or its Affiliates shall be
billed only on a per foot, per day, or per hour rate, or some
combination thereof. No turnkey drilling contracts shall be made
between the Managing General Partner or its Affiliates and the
Partnership. Neither the Managing General Partner nor its Affiliates
shall profit by drilling in contravention of its fiduciary obligations
to the Partnership. Any such services for which the Managing General
Partner or an Affiliate is to receive compensation shall be embodied in
a written contract which precisely describes the services to be rendered
and all compensation to be paid.
(f) Advance payments by the Partnership to the Managing General
Partner are prohibited, except where necessary to secure tax benefits
of prepaid drilling costs.
(g) Neither the Managing General Partner nor its Affiliates
shall make any future commitments of the Partnership's production which
do not primarily benefit the Partnership, nor shall the Managing General
Partner or any Affiliate utilize Partnership funds as compensating
balances for the benefit of the Managing General Partner or the
Affiliate.
(h) No rebates or give-ups may be received by the Managing
General Partner or any of its Affiliates, nor may the Managing General
Partner or any Affiliate participate in any reciprocal business arrangements
which would circumvent these restrictions.
(i) During a period of five years from the date of formation of
the Partnership, if the Managing General Partner or any of its
Affiliates proposes to acquire from an unaffiliated person an interest
in a Prospect in which the Partnership possesses an interest or in a
Prospect in which the Partnership's interest has been terminated without
compensation within one year preceding such proposed acquisition, the
following conditions shall apply:
(1) If the Managing General Partner or the Affiliate does not
currently own property in the Prospect separately from the
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Partnership, then neither the Managing General Partner nor
the Affiliate shall be permitted to purchase an interest
in the Prospect.
(2) If the Managing General Partner or the Affiliate currently
owns a proportionate interest in the Prospect separately
from the Partnership, then the interest to be acquired
shall be divided between the Partnership and the
Managing General Partner or the Affiliate in the same
proportion as is the other property in the Prospect;
provided however, if cash or financing is not available
to the Partnership to enable it to consummate a purchase of
the additional interest to which it is entitled, then
neither the Managing General Partner nor the Affiliate shall
be permitted to purchase any additional interest in the
Prospect.
(j) If the Partnership acquires property pursuant to a farmout or
joint venture from an affiliated program, the Managing General Partner's
and/or its Affiliates' aggregate compensation associated with the
property and any direct and indirect ownership interest in the property
may not exceed the lower of the compensation and ownership interest the
Managing General Partner and/or its Affiliates could receive if the
property were separately owned or retained by either one of the
programs.
(k) Neither the Managing General Partner nor any Affiliate,
including affiliated programs, may purchase or acquire any property from
the Partnership, directly or indirectly, except pursuant to transactions
that are fair and reasonable to the Investor Partners of the Partnership
and then subject to the following conditions:
(1) A sale, transfer or conveyance, including a farmout, of an
undeveloped property from the Partnership to the Managing
General Partner or an Affiliate, other than an affiliated
program, must be made at the higher of cost or fair market
value.
(2) A sale, transfer or conveyance of a developed property from
the Partnership to the Managing General Partner or an
Affiliate, other than an affiliated program in which the
interest of the Managing General Partner is substantially
similar to or less than its interest in the subject
Partnership, shall not be permitted except in connection
with the liquidation of the Partnership and then only at
fair market value.
(3) Except in connection with farmouts or joint ventures made in
compliance with Section 5.07(j) above, a transfer of an
undeveloped property from the Partnership to an affiliated
drilling program must be made at fair market value if the
property has been held for more than two years. Otherwise,
if the Managing General Partner deems it to be in the best
interest of the Partnership, the transfer may be made at cost.
(4) Except in connection with farmouts or joint ventures made
in compliance with Section 5.07(j) above, a transfer of any
type of property from the Partnership to an affiliated
production purchase or income program must be made at
fair market value if the property has been held for more
than six months or
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there have been significant expenditures made in connection
with the property. Otherwise, if the Managing General
Partner deems it to be in the best interest of the
Partnership, the transfer may be made at cost as adjusted
for intervening operations.
(l) If the Partnership participates in other partnerships or joint
ventures (multi-tier arrangements), the terms of any such arrangements
shall not result in the circumvention of any of the requirements or
prohibitions contained in this Partnership Agreement, including the
following:
(1) there will be no duplication or increase in organization and
offering expenses, the Managing General Partner's
compensation, Partnership expenses or other fees and costs;
(2) there will be no substantive alteration in the fiduciary and
contractual relationship between the Managing General
Partner and the Investor Partners; and
(3) there will be no diminishment in the voting rights of the
Investor Partners.
(m) In connection with a proposed Roll-Up, the following shall apply:
(1) An appraisal of all Partnership assets shall be obtained
from a competent independent expert. If the appraisal
will be included in a prospectus used to offer the
securities of a Roll-Up Entity, the appraisal shall be
filed with the Securities and Exchange Commission and the
Administrator as an exhibit to the registration
statement for the offering. The appraisal shall be based
on all relevant information, including current reserve
estimates prepared by an independent petroleum consultant,
and shall indicate the value of the Partnership's assets
assuming an orderly liquidation as of a date immediately
prior to the announcement of the proposed Roll-Up
transaction. The appraisal shall assume an orderly
liquidation of Partnership assets over a 12-month period.
The terms of the engagement of the independent expert shall
clearly state that the engagement is for the benefit of the
Partnership and the Investor Partners. A summary of the
independent appraisal, indicating all material assumptions
underlying the appraisal, shall be included in a report to
the Investor Partners in connection with a proposed Roll-Up.
(2) In connection with a proposed Roll-Up, Investor Partners
who vote "no" on the proposal shall be offered the choice of:
(i) accepting the securities of the Roll-Up Entity
offered in the proposed Roll-Up; or
(ii) (a) remaining as Investor Partners in the Partnership
and preserving their interests therein on the same
terms and conditions as existed previously; or (b)
receiving cash in an amount equal to the
Investor Partners' pro-rata share of the appraised
value of the net assets of the Partnership.
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(3) The Partnership shall not participate in any proposed
Roll-Up which, if approved, would result in the
diminishment of any Investor Partner's voting rights
under the Roll-Up Entity's chartering agreement. In no
event shall the democracy rights of Investor Partners in
the Roll-Up Entity be less than those provided for under
Sections 7.07 and 7.08 of this Agreement.
If the Roll-Up Entity is a corporation, the democracy
rights of Investor Partners shall correspond to the
democracy rights provided for in this Agreement to the
greatest extent possible.
(4) The Partnership shall not participate in any proposed
Roll-Up transaction which includes provisions which would
operate to materially impede or frustrate the
accumulation of shares by any purchaser of the
securities of the Roll-Up Entity (except
to the minimum extent necessary to preserve the tax status
of the Roll-Up Entity); nor shall the Partnership
participate in any proposed Roll-Up transaction which
would limit the ability of an Investor Partner to
exercise the voting rights of its securities of the
Roll-Up Entity on the basis of the number of
Partnership Units held by that Investor Partner.
(5) The Partnership shall not participate in a Roll-Up in which
Investor Partners' rights of access to the records of the
Roll-Up Entity will be less than those provided for under
Section 8.01 of this Agreement.
(6) The Partnership shall not participate in any proposed
Roll-Up transaction in which any of the costs of the
transaction would be borne by the Partnership if the
Roll-Up is not approved by the Investor Partners.
(7) The Partnership shall not participate in a Roll-Up
transaction unless the Roll-Up transaction is approved
by at least 66 2/3% in interest of the Investor Partners.
ARTICLE VI
Managing General Partner
6.01 Managing General Partner. The Managing General Partner shall have
the sole and exclusive right and power to manage and control the affairs
of and to operate the Partnership and to do all things necessary to carry
on the business of the Partnership for the purposes described in Section
1.03 hereof and to conduct the activities of the Partnership as set forth
in Article V hereof. No financial institution or any other person, firm,
or corporation dealing with the Managing General Partner shall be required
to ascertain whether the Managing General Partner is acting in accordance
with this Agreement, but such financial institution or such other person,
firm, or corporation shall be protected in relying solely upon the deed,
transfer, or assurance of and the execution of such instrument or
instruments by the Managing General Partner. The Managing General Partner
shall devote so much of its time to the business of the Partnership as in
its judgment the conduct of the Partnership's business
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shall reasonably require and shall not be obligated to do or perform any
act or thing in connection with the business of the Partnership not
expressly set forth herein. The Managing General Partner may engage in
business ventures of any nature and description independently or with
others and neither the Partnership nor any of its Investor Partners shall
have any rights in and to such independent ventures or the income or
profits derived therefrom. However, except as otherwise provided herein,
the Managing General Partner and any of its Affiliates may pursue business
opportunities that are consistent with the Partnership's investment
objectives for their own account only after they have determined that such
opportunity either cannot be pursued by the Partnership because of
insufficient funds or because it is not appropriate for the Partnership
under the existing circumstances.
6.02 Authority of Managing General Partner. The Managing General
Partner is specifically authorized and empowered, on behalf of the
Partnership, and by consent of the Investor Partners herein given, to do
any act or execute any document or enter into any contract or any
agreement of any nature necessary or desirable, in the opinion of the
Managing General Partner, in pursuance of the purposes of the
Partnership. Without limiting the generality of the foregoing, in
addition to any and all other powers conferred upon the Managing General
Partner pursuant to this Agreement and the Act, and except as otherwise
prohibited by law or hereunder, the Managing General Partner shall have
the power and authority to:
(a) Acquire leases and other interests in oil and/or gas
properties in furtherance of the Partnership's business;
(b) Enter into and execute pooling agreements, farm out
agreements, operating agreements, unitization agreements, dry and bottom
hole and acreage contribution letters, construction contracts, and any
and all documents or instruments customarily employed in the oil and gas
industry in connection with the acquisition, sale, exploration,
development, or operation of oil and gas properties, and all other
instruments deemed by the Managing General Partner to be necessary or
appropriate to the proper operation of oil or gas properties or to
effectively and properly perform its duties or exercise its powers
hereunder;
(c) Make expenditures and incur any obligations it deems
necessary to implement the purposes of the Partnership; employ and retain
such personnel as it deems desirable for the conduct of the Partnership's
activities, including employees, consultants, and attorneys; and
exercise on behalf of the Partnership, in such manner as the Managing
General Partner in its sole judgment deems best, of all rights,
elections, and obligations granted to or imposed upon the Partnership;
(d) Manage, operate, and develop any Partnership property, and
enter into operating agreements with respect to properties acquired by
the Partnership, including an operating agreement with the Managing
General Partner as described in the Prospectus, which agreements may
contain such terms, provisions, and conditions as are usual and
customary within the industry and as the Managing General Partner shall
approve;
(e) Compromise, sue, or defend any and all claims in favor of
or against the Partnership;
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(f) Subject to the provisions of Section 8.04 hereof, make or
revoke any election permitted the Partnership by any taxing authority;
(g) Perform any and all acts it deems necessary or appropriate
for the protection and preservation of the Partnership assets;
(h) Maintain at the expense of the Partnership such insurance
coverage for public liability, fire and casualty, and any and all other
insurance necessary or appropriate to the business of the Partnership
in such amounts and of such types as it shall determine from time to
time;
(i) Buy, sell, or lease property or assets on behalf of the
Partnership;
(j) Enter into agreements to hire services of any kind or
nature;
(k) Assign interests in properties to the Partnership;
(l) Enter into soliciting dealer agreements and perform all of
the Partnership's obligations thereunder, to issue and sell Units pursuant
to the terms and conditions of this Agreement, the Subscription
Agreements, and the Prospectus, to accept and execute on behalf of the
Partnership Subscription Agreements, and to admit original and
substituted Partners; and
(m) Perform any and all acts, and execute any and all documents
it deems necessary or appropriate to carry out the purposes of the
Partnership.
6.03 Certain Restrictions on Managing General Partner's Power and
Authority. Notwithstanding any other provisions of this Agreement to the
contrary, neither the Managing General Partner nor any Affiliate of the
Managing General Partner shall have the power or authority to, and shall
not, do, perform, or authorize any of the following:
(a) Borrow any money in the name or on behalf of the
Partnership;
(b) Use any revenues from Partnership operations for the
purposes of acquiring Leases in new or unrelated Prospects or paying any
Organization and Offering Expenses; provided, however, that revenues
from Partnership operations may be used for other Partnership
operations, including without limitation for the purposes of drilling,
completing, maintaining, recompleting, and operating wells on existing
Partnership Prospects and acquiring and developing new Leases to the
extent such Leases are considered by the Managing General Partner in its
sole discretion to be a part of a Prospect in which the Partnership then
owns a Lease;
(c) Without having first received the prior consent of the
holders of a majority of the then outstanding Units entitled to vote,
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(i) sell all or substantially all of the assets of the
Partnership (except upon liquidation of the Partnership pursuant
to Article IX hereof), unless cash funds of the Partnership are
insufficient to pay the obligations and other liabilities of the
Partnership;
(ii) dispose of the good will of the Partnership;
(iii) do any other act which would make it impossible to carry
on the ordinary business of the Partnership; or
(iv) agree to the termination or amendment of any operating
agreement to which the Partnership is a party, or waive any rights
of the Partnership thereunder, except for amendments to the
operating agreement which the Managing General Partner believes are
necessary or advisable to ensure that the operating agreement
conforms to any changes in or modifications to the Code or that do
not adversely affect the Investor Partners in any material respect;
(d) Guarantee in the name or on behalf of the Partnership the
payment of money or the performance of any contract or other obligation
of any Person other than the Partnership;
(e) Bind or obligate the Partnership with respect to any matter
outside the scope of the Partnership business;
(f) Use the Partnership name, credit, or property for other
than Partnership purposes;
(g) Take any action, or permit any other person to take any
action, with respect to the assets or property of the Partnership which
does not benefit the Partnership, including, among other things,
utilization of funds of the Partnership as compensating balances for its
own benefit or the commitment of future production;
(h) Benefit from any arrangement for the marketing of oil and
gas production or other relationships affecting the property of the Managing
General Partner and the Partnership, unless such benefits are fairly and
equitably apportioned among the Managing General Partner, its
Affiliates, and the Partnership;
(i) Utilize Partnership funds to invest in the securities of
another person except in the following instances:
(1) investments in working interests or undivided lease
interests made in the ordinary course of the
Partnership's business;
(2) temporary investments made in compliance with Section
2.02(f) of this Agreement;
(3) investments involving less than 5% of Partnership capital
which are a necessary and incidental part of a property
acquisition transaction; and
(4) investments in entities established solely to limit the
Partnership's liabilities associated with the ownership
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or operation of property or equipment, provided, in such
instances duplicative fees and expenses shall be
prohibited.
(j) Vote with respect to any Unit held by it; or
(k) Sell, transfer, or assign its interest (except for a
collateral assignment which may be granted to a bank or other financial
institution) in the Partnership, or any part thereof, or otherwise to
withdraw as Managing General Partner of the Partnership without one
hundred twenty (120) days prior written notice and the written consent
of Investor Partners owning a majority of the then outstanding Units.
6.04 Indemnification of Managing General Partner. The Managing General
Partner shall have no liability to the Partnership or to any Investor
Partner for any loss suffered by the Partnership which arises out of any
action or inaction of the Managing General Partner if the Managing General
Partner, in good faith, determined that such course of conduct was in the
best interest of the Partnership, that the Managing General Partner was
acting on behalf of or performing services for the Partnership, and that
such course of conduct did not constitute negligence or misconduct of the
Managing General Partner. The Managing General Partner shall be
indemnified by the Partnership against any losses, judgments, liabilities,
expenses, and amounts paid in settlement of any claims sustained by it in
connection with the Partnership, provided that the Managing General
Partner has determined in good faith that the course of conduct which
caused the loss or liability was in the best interests of the Partnership,
that the Managing General Partner was acting on behalf of or performing
services for the Partnership, and that the same were not the result of
negligence or misconduct on the part of the Managing General Partner.
Indemnification of the Managing General Partner is recoverable only from
the tangible net assets of the Partnership, including the insurance
proceeds from the Partnership's insurance policies and the insurance and
indemnification of the Partnership's subcontractors, and is not
recoverable from the Investor Partners.
Notwithstanding the above, the Managing General Partner and any person
acting as a broker-dealer shall not be indemnified for liabilities arising
under Federal and state securities laws unless (a) there has been a
successful adjudication on the merits of each count involving securities
law violations, (b) such claims have been dismissed with prejudice on the
merits by a court of competent jurisdiction, or (c) a court of competent
jurisdiction approves a settlement of such claims against a particular
indemnitee and finds that indemnification of the settlement and the
related costs should be made, and the court considering the request for
indemnification has been advised of the position of the Securities and
Exchange Commission and of any state securities regulatory authority in
which securities of the Partnership were offered or sold as to
indemnification for violations of securities laws; provided however, the
court need only be advised of the positions of the securities regulatory
authorities of those states (i) which are specifically set forth in the
program agreement and (ii) in which plaintiffs claim they were offered or
sold program units.
In any claim for indemnification for Federal or state securities laws
violations, the party seeking indemnification shall place before the court
the position of the Securities and Exchange Commission and the
Massachusetts Securities Division or respective state securities division,
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as the case may be, with respect to the issue of indemnification for
securities law violations.
The advancement of Partnership funds to a sponsor or its affiliates for
legal expenses and other costs incurred as a result of any legal action
for which indemnification is being sought is permissible only if the
Partnership has adequate funds available and the following conditions are
satisfied:
(a) the legal action relates to acts or omissions with respect to the
performance of duties or services on behalf of the Partnership, and
(b) the legal action is initiated by a third party who is not a
participant, or the legal action is initiated by a participant and
a court of competent jurisdiction specifically approves such
advancement, and
(c) the sponsor or its affiliates undertake to repay the advanced funds
to the Partnership, together with the applicable legal rate of
interest thereon, in cases in which such party is found not to be
entitled to indemnification.
The Partnership shall not incur the cost of the portion of any insurance
which insures the Managing General Partner against any liability as to
which the Managing General Partner is herein prohibited from being
indemnified.
6.05 Withdrawal. (a) Notwithstanding the limitations contained in
Section 6.03(l) hereof, the Managing General Partner shall have the
right, by giving written notice to the other Partners, to substitute in
its stead as managing general partner any successor entity or any entity
controlled by the Managing General Partner, provided that the successor
Managing General Partner must have a tangible net worth of at least $5
million, and the Investor Partners, by execution of this Agreement,
expressly consent to such a transfer, unless it would adversely affect
the status of the Partnership as a partnership for federal income tax
purposes.
(b) The Managing General Partner may not voluntarily withdraw
from the Partnership prior to the Partnership's completion of its primary
drilling and/or acquisition activities, and then only after giving 120
days written notice. The Managing General Partner may not partially
withdraw its property interests held by the Partnership unless such
withdrawal is necessary to satisfy the bona fide request of its
creditors or approved by a majority-in-interest vote of the Investor
Partners. The Managing General Partner shall fully indemnify the
Partnership against any additional expenses which may result from a
partial withdrawal of property interests and such withdrawal may not
result in a greater amount of direct costs or administrative costs being
allocated to the Investor Partners. The withdrawing Managing General
Partner shall pay all expenses incurred as a result of its withdrawal.
6.06 Management Fee. The Partnership shall pay the Managing General
Partner, on the date the Partnership is organized (as set forth in Section
1.01), a one-time management fee equal to 2.5% of the total Subscriptions.
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6.07 Tax Matters and Financial Reporting Partner. The Managing General
Partner shall serve as the Tax Matters Partner for purposes of Code
Sections 6221 through 6233 and as the Financial Reporting Partner. The
Partnership may engage its accountants and/or attorneys to assist the Tax
Matters Partner in discharging its duties hereunder.
ARTICLE VII
Investor Partners
7.01 Management. No Investor Partner shall take part in the control
or management of the business or transact any business for the
Partnership, and no Investor Partner shall have the power to sign for or
bind the Partnership. Any action or conduct of Investor Partners on
behalf of the Partnership is hereby expressly prohibited. Any Investor
Partner who violates this Section 7.01 shall be liable to the remaining
Investor Partners, the Managing General Partner, and the Partnership for
any damages, costs, or expenses any of them may incur as a result of such
violation. The Investor Partners hereby grant to the Managing General
Partner or its successors or assignees the exclusive authority to manage
and control the Partnership business in its sole discretion and to thereby
bind the Partnership and all Partners in its conduct of the Partnership
business. Investor Partners shall have the right to vote only with
respect to those matters specifically provided for in these Articles. No
Investor Partner shall have the authority to:
(a) Assign the Partnership property in trust for creditors or
on the assignee's promise to pay the debts of the Partnership;
(b) Dispose of the goodwill of the business;
(c) Do any other act which would make it impossible to carry on
the ordinary business of the Partnership;
(d) Confess a judgment;
(e) Submit a Partnership claim or liability to arbitration or
reference;
(f) Make a contract or bind the Partnership to any agreement or
document;
(g) Use the Partnership's name, credit, or property for any
purpose;
(h) Do any act which is harmful to the Partnership's assets or
business or by which the interests of the Partnership shall be imperiled
or prejudiced; or
(i) Perform any act in violation of any applicable law or
regulations thereunder, or perform any act which is inconsistent with
the terms of this Agreement.
7.02 Indemnification of Additional General Partners. The Managing
General Partner agrees to indemnify each of the Additional General
Partners for the amounts of obligations, risks, losses, or judgments of
the Partnership or the Managing General Partner which exceed the amount of
applicable insurance coverage and amounts which would become available
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from the sale of all Partnership assets. Such indemnification applies to
casualty losses and to business losses, such as losses incurred in
connection with the drilling of an unproductive well, to the extent such
losses exceed the Additional General Partners' interest in the
undistributed net assets of the Partnership. If, on the other hand, such
excess obligations are the result of the negligence or misconduct of an
Additional General Partner, or the contravention of the terms of the
Partnership Agreement by the Additional General Partner, then the
foregoing indemnification by the Managing General Partner shall be
unenforceable as to such Additional General Partner and such Additional
General Partner shall be liable to all other Partners for damages and
obligations resulting therefrom.
7.03 Assignment of Units.
(a) An Investor Partner may transfer all or any portion of his
Units and the transferee shall become a Substituted Investor Partner
(subject to all duties and obligations of an Investor Partner, including
those contained in Section 4.04 herein, except to the extent excepted
in the Act) subject to the following conditions (any transfer of such
Units satisfying such conditions being referred to herein as a
"Permitted Transfer"):
(i) Except in the case of a transfer of Units at death or
involuntarily by operation of law, the transferor and transferee
shall execute and deliver to the Partnership such documents and
instruments of conveyance as may be necessary or appropriate in the
opinion of counsel to the Partnership to effect such transfer and
to confirm the agreement of the transferee to be bound by the
provisions of this Article VII. In any case not described in the
preceding sentence, the transfer shall be confirmed by presentation
to the Partnership of legal evidence of such transfer, in form and
substance satisfactory to counsel to the Partnership. In all
cases, the Partnership shall be reimbursed by the transferor and/or
transferee for all costs and expenses that it reasonably incurs in
connection with such transfer;
(ii) The transferor and transferee shall furnish the Partnership
with the transferee's taxpayer identification number and sufficient
information to determine the transferee's initial tax basis in the
Units transferred; and
(iii) The written consent of the Managing General Partner to
such transfer shall have been obtained, the granting or denial of
which shall be within the absolute discretion of the Managing
General Partner.
(b) A Person who acquires one or more Units but who is not
admitted as a Substituted Investor Partner pursuant to Section 7.03(c)
hereof shall be entitled only to allocations and distributions with
respect to such Units in accordance with this Agreement, but shall have
no right to any information or accounting of the affairs of the
Partnership, shall not be entitled to inspect the books or records of
the Partnership, and shall not have any of the rights of an Additional
General Partner or a Limited Partner under the Act or the Agreement.
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(c) Subject to the other provisions of this Article VII, a
transferee of Units may be admitted to the Partnership as a Substituted
Investor Partner only upon satisfaction of the conditions set forth
below in this Section 7.03(c):
(i) The Managing General Partner consents to such admission,
which consent can be withheld in its absolute discretion;
(ii) The Units with respect to which the transferee is being
admitted were acquired by means of a Permitted Transfer;
(iii) The transferee becomes a party to this Agreement as a
Partner and executes such documents and instruments as the Managing
General Partner may reasonably request (including, without
limitation, amendments to the Certificate of Limited Partnership)
as may be necessary or appropriate to confirm such transferee as a
Partner in the Partnership and such transferee's agreement to be
bound by the terms and conditions hereof;
(iv) The transferee pays or reimburses the Partnership for all
reasonable legal, filing, and publication costs that the
Partnership incurs in connection with the admission of the
transferee as a Partner with respect to the transferred Units; and
(v) If the transferee is not an individual of legal majority,
the transferee provides the Partnership with evidence
satisfactory to counsel for the Partnership of the authority of
the transferee to become a Partner and to be bound by the terms
and conditions of this Agreement.
(vi) In any calendar quarter in which a Substituted Investor
Partner is admitted to the Partnership, the Managing General
Partner shall amend the certificate of limited partnership to
effect the substitution of such Substituted Investor Partners,
although the Managing General Partner may do so more frequently.
In the case of assignments, where the assignee does not become a
Substituted Investor Partner, the Partnership shall recognize the
assignment not later than the last day of the calendar month
following receipt of notice of assignment and required
documentation.
(d) Each Investor Partner hereby covenants and agrees with the
Partnership for the benefit of the Partnership and all Partners that
(i) he is not currently making a market in Units and (ii) he will not
transfer any Unit on an established securities market or a secondary
market (or the substantial equivalent thereof) within the meaning of
Code Section 7704(b) (and any regulations, proposed regulations, revenue
rulings, or other official pronouncements of the Service or Treasury
Department that may be promulgated or published thereunder). Each
Investor Partner further agrees that he will not transfer any Unit to
any Person unless such Person agrees to be bound by this Section 7.03
and to transfer such Units only to Persons who agree to be similarly
bound.
7.04 Prohibited Transfers.
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(a) Any purported Transfer of Units that is not a Permitted
Transfer shall be null and void and of no effect whatever; provided,
that, if the Partnership is required to recognize a transfer that is not
a Permitted Transfer (or if the Managing General Partner, in its sole
discretion, elects to recognize a transfer that is not a Permitted
Transfer), the interest transferred shall be strictly limited to the
transferor's rights to allocations and distributions as provided by this
Agreement with respect to the transferred Units, which allocations and
distributions may be applied (without limiting any other legal or
equitable rights of the Partnership) to satisfy the debts, obligations,
or liabilities for damages that the transferor or transferee of such
Units may have to the Partnership.
(b) In the case of a transfer or attempted transfer of Units
that is not a Permitted Transfer, the parties engaging or attempting to
engage in such transfer shall be liable to indemnify and hold harmless
the Partnership and the other Partners from all cost, liability, and
damage that any of such indemnified Persons may incur (including,
without limitation, incremental tax liability and lawyers fees and
expenses) as a result of such transfer or attempted transfer and efforts
to enforce the indemnity granted hereby.
7.05 Withdrawal by Investor Partners. Neither a Limited Partner nor
an Additional General Partner may withdraw from the Partnership, except as
otherwise provided in this Agreement.
7.06 Removal of Managing General Partner.
(a) The Managing General Partner may be removed at any time,
upon ninety (90) days prior written notice, with the consent of Investor
Partners owning a majority of the then outstanding Units, and upon the
selection of a successor managing general partner or partners, within
such ninety-day period by Investor Partners owning a majority of the
then outstanding Units.
(b) Any successor Managing General Partner may be removed upon
the terms and conditions provided in this Section.
(c) In the event a managing general partner is removed, its
respective interest in the assets of the Partnership shall be determined
by independent appraisal by a qualified independent petroleum
engineering consultant who shall be selected by mutual agreement of the
Managing General Partner and the incoming sponsor. Such appraisal will
take into account an appropriate discount to reflect the risk of
recovery of oil and gas reserves, and, at its election, the removed
managing general partner's interest in the Partnership assets may be
distributed to it or the interest of the managing general partner in the
Partnership may be retained by it as a Limited Partner in the successor
limited partnership; provided, however, that if immediate payment to the
removed managing general partner would impose financial or operational
hardship upon the Partnership, as determined by the successor managing
general partner in the exercise of its fiduciary duties to the
Partnership, payment (plus reasonable interest) to the removed managing
general partner may be postponed to that time when, in the determination
of the successor managing general partner, payment will not cause a
hardship to the Partnership. The cost of such appraisal shall be borne
by the Partnership. The successor managing general partner shall have
the option to purchase at least 20% of the removed
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managing general partner's interest for the value determined by the
independent appraisal. The removed managing general partner, at the
time of its removal shall cause, to the extent it is legally possible,
its successor to be transferred or assigned all its rights, obligations,
and interests in contracts entered into by it on behalf of the
Partnership. In any event, the removed managing general partner shall
cause its rights, obligations, and interests in any such contract to
terminate at the time of its removal.
(d) Upon effectiveness of the removal of the managing general
partner, the assets, books, and records of the Partnership shall be
surrendered to the successor managing general partner, provided that the
successor managing general partner shall have first (i) agreed to accept
the responsibilities of the managing general partner, and (ii) made
arrangements satisfactory to the original managing general partner to
remove such managing general partner from personal liability on any
Partnership borrowings or, if any Partnership creditor will not consent
to such removal, agreed to indemnify the original managing general
partner for any subsequent liabilities in respect to such borrowings.
Immediately after the removal of the managing general partner, the
successor managing general partner shall prepare, execute, file for
recordation, and cause to be published, such notices or certificates as
may be required by the Act.
7.07 Calling of Meetings. Investor Partners owning 10% or more of the
then outstanding Units entitled to vote shall have the right to request
that the Managing General Partner call a meeting of the Partners. The
Managing General Partner shall call such a meeting and shall deposit in
the United States mails within fifteen days after receipt of such request,
written notice to all Investor Partners of the meeting and the purpose of
the meeting, which shall be held on a date not less than thirty nor more
than sixty days after the date of mailing of such notice, at a reasonable
time and place. Investor Partners shall have the right to submit
proposals to the Managing General Partner for inclusion in the voting
materials for the next meeting of Investor Partners for consideration and
approval by the Investor Partners. Investor Partners shall have the right
to vote in person or by proxy.
7.08 Additional Voting Rights. Investor Partners shall be entitled to
all voting rights granted to them by and under this Agreement and as
specified by the Act. Each Unit is entitled to one vote on all matters;
each fractional Unit is entitled to that fraction of one vote equal to the
fractional interest in the Unit. Except as otherwise provided herein or
in the Prospectus, at any meeting of Investor Partners, a vote of a
majority of Units represented at such meeting, in person or by proxy, with
respect to matters considered at the meeting at which a quorum is present
shall be required for approval of any such matters. In addition, except
as otherwise provided in this Section and in Section 5.07(m), holders of
a majority of the then outstanding Units may, without the concurrence of
the Managing General Partner, vote to (a) approve or disapprove the sale
of all or substantially all of the assets of the Partnership, (b) dissolve
the Partnership, (c) remove the Managing General Partner and elect a new
managing general partner, (d) amend the Agreement, (e) elect a new
managing general partner if the managing general partner elects to
withdraw from the Partnership, and (f) cancel any contract for services
with the Managing General Partner or any Affiliates without penalty upon
sixty days' notice. The Partnership shall not participate in a Roll-Up
unless the Roll-Up is approved by at least 66 2/3% in interest of the
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Investor Partners. A majority in interest of the then outstanding Units
entitled to vote shall constitute a quorum. In determining the requisite
percentage in interest of Units necessary to approve a matter on which the
Managing General Partner and its Affiliates may not vote or consent, any
Units owned by the Managing General Partner and its Affiliates shall not
be included. With respect to the merger or consolidation of the
Partnership or the sale of all or substantially all of the assets of the
Partnership, Investor Partners shall have the right to exercise
dissenter's rights in accordance with Section 31-1-123 of the West
Virginia Corporation Law.
7.09 Voting by Proxy. The Investor Partners may vote either in person
or by proxy.
7.10 Conversion of Additional General Partner Interests into Limited
Partner Interests.
(a) As provided herein, Additional General Partners may elect
to convert, transfer, and exchange their interests for Limited Partner
interests in the Partnership upon receipt by the Managing General
Partner of written notice of such election. An Additional General
Partner may request conversion of his interests for Limited Partner
interests at any time after the earlier of (i) one year following the
closing of the securities offering which relates to the Agreement and
the disbursement to the Partnership of the proceeds of such securities
offering or (ii) when all wells have been placed into production.
(b) The Managing General Partner shall notify all Additional
General Partners at least 30 days prior to any material change in the
amount of the Partnership's insurance coverage. Within this 30-day
period, and notwithstanding Section 7.10(a), Additional General Partners
shall have the right to immediately convert their Units into Units of
limited partnership interest by giving written notice to the Managing
General Partner.
(c) The Managing General Partner shall convert the interests of
all Additional General Partners in a particular Partnership to interests
of Limited Partners in that Partnership upon completion of drilling of
that Partnership.
(d) The Managing General Partner shall cause the conversion to
be effected as promptly as possible as prudent business judgment dictates.
Conversion of an Additional General Partnership interest to a Limited
Partnership interest in a particular Partnership shall be conditioned
upon a finding by the Managing General Partner that such conversion will
not cause a termination of the Partnership for federal income tax
purposes, and will be effective upon the Managing General Partner's
filing an amendment to its Certificate of Limited Partnership. The
Managing General Partner is obligated to file an amendment to its
Certificate at any time during the full calendar month after receipt of
the required notice of the Additional General Partner and a
determination of the Managing General Partner that the conversion will
not constitute a termination of the Partnership for tax purposes.
Effecting conversion is subject to the satisfaction of the condition
that the electing Additional General Partner provide written notice to
the Managing General Partner of such intent to convert. Upon such
transfer and exchange, such Additional General Partners shall be Limited
Partners; however, they will
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remain liable to the Partnership for any additional Capital
Contribution(s) required for their proportionate share of any
Partnership obligation or liability arising prior to the conversion.
(e) Limited Partners may not convert and/or exchange their
interests for Additional General Partner interests.
7.11 Unit Repurchase Program.
(a) Beginning with the third anniversary of the date of the
first cash distribution of the Partnership, Investor Partners may tender
their Units to the Managing General Partner for repurchase, subject to the
Managing General Partner's financial ability to repurchase and the
Managing General Partner's receipt of an opinion of counsel that the
Managing General Partner's repurchase of Units pursuant to this Section
will not cause the Partnership to be treated as a "publicly traded
partnership" for purposes of Code Sections 469 and 7704. Failure to
receive such opinion shall preclude the Managing General Partner from
making any offers to repurchase Units. Subject to such financial
condition and legal opinion, the Managing General Partner shall offer to
annually repurchase for cash a minimum of 10% of the Units originally
subscribed to in the Partnership.
(b) The Unit Repurchase Program shall be subject to the
following conditions:
(i) The Managing General Partner must receive written notification
from the particular Investor Partner of such Partner's intention to
exercise the repurchase right; and
(ii) The Managing General Partner shall provide the Investor
Partner a written offer of a specified price for purchase of the
particular Units within 30 days of the Managing General Partner's
receipt of written notification; and
(iii) The Managing General Partner's offer shall remain open for
30 days after the Managing General Partner's mailing of the offer to
the Investor Partner.
(c) The Managing General Partner shall not favor one particular
Partnership of which it is a Managing General Partner over another in the
repurchase of Units. Each Partnership shall stand on equal footing before
the Managing General Partner. To the extent that the Managing General
Partner is unable, due to its financial condition or limitations imposed
by the Code or the Managing General Partner's loan agreement(s) with
banks, to repurchase all Units tendered, each tendering Investor Partner
shall be entitled to have his Units repurchased on a "first come-first
served" basis, regardless of Partnership, provided that the Managing
General Partner determines that the repurchase of a particular Investor
Partner's Units will not result in the termination of the Partnership for
federal income tax purposes and in the Partnership's being treated as a
"publicly traded partnership." If more than 10% of the Units of a
particular Partnership are tendered during that Partnership's taxable
year, Units shall be purchased on a "first come-first served" basis with
respect to that Partnership.
(d) The offer price which the Managing General Partner shall
make shall be a cash amount equal to three times cash distributions
attributable to the tendered Unit from production for the 12 months prior
to the month in which the above-referenced written notification is
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actually received by the Managing General Partner at its corporate
offices. The Managing General Partner may, in its sole and absolute
discretion, increase the offer price for interests tendered for sale.
(e) Upon any repurchase, the Managing General Partner shall hold
such purchased Units for its own use and not for resale and it shall not
create a market in the Units.
7.12 Liability of Partners. Except as otherwise provided in this
Agreement or as otherwise provided by the Act, each General Partner shall
be jointly and severally liable for the debts and obligations of the
Partnership. In addition, each Additional General Partner shall be
jointly and severally liable for any wrongful acts or omissions of the
Managing General Partner and/or the misapplication of money or property of
a third party by the Managing General Partner acting within the scope of
its apparent authority to the extent such acts or omissions are chargeable
to the Partnership.
ARTICLE VIII
Books and Records
8.01 Books and Records.
(a) For accounting and income tax purposes, the Partnership
shall operate on a calendar year.
(b) The Managing General Partner shall keep just and true
records and books of account with respect to the operations of the
Partnership and shall maintain and preserve during the term of the
Partnership and for four years thereafter all such records, books of
account, and other relevant Partnership documents. The Managing General
Partner shall maintain for at least six years all records necessary to
substantiate the fact that Units were sold only to purchasers for whom
such Units were suitable. Such books shall be maintained at the
principal place of business of the Partnership and shall be kept on the
accrual method of accounting.
(c) The Managing General Partner shall keep or cause to be kept
complete and accurate books and records with respect to the
Partnership's business, which books and records shall at all times be
kept at the principal office of the Partnership. Any records maintained
by the Partnership in the regular course of its business, including the
names and addresses of Investor Partners, books of account, and records
of Partnership proceedings, may be kept on or be in the form of RAM
disks, magnetic tape, photographs, micrographics, or any other
information storage device, provided that the records so kept are
convertible into clearly legible written form within a reasonable period
of time. The books and records of the Partnership shall be made
available for review by any Investor Partner or his representative at
any reasonable time.
(d) (i) An alphabetical list of the names, addresses and
business telephone numbers of the Investor Partners of the
Partnership along with the number of Units held by each of them
(the "participant list") shall be maintained as a part of the
books and records of the Partnership and shall be available for
the inspection by any Investor Partner
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or its designated agent at the home office of the Partnership upon
the request of the Investor Partner;
(ii) The participant list shall be updated at least quarterly
to reflect changes in the information contained therein;
(iii) A copy of the participant list shall be mailed to any
Investor Partner requesting the participant list within ten days of
the request. The copy of the participant list shall be printed in
alphabetical order, on white paper, and in a readily readable type
size (in no event smaller than 10-point type). A reasonable charge
for copy work may be charged by the Partnership.
(iv) The purposes for which an Investor Partner may request a
copy of the participant list include, without limitation, matters
relating to voting rights under the Partnership Agreement and the
exercise of Investor Partners' rights under federal proxy laws; and
(v) If the Managing General Partner of the Partnership
neglects or refuses to exhibit, produce, or mail a copy of the
participant list as requested, the Managing General Partner shall
be liable to any Investor Partner requesting the list for the
costs, including attorneys fees, incurred by that Investor Partner
for compelling the production of the participant list, and for
actual damages suffered by any Investor Partner by reason of such
refusal or neglect. It shall be a defense that the actual purpose
and reason for the requests for inspection or for a copy of the
participant list is to secure the list of Investor Partners or other
information for the purpose of selling such list or information or
copies thereof, or of using the same for a commercial purpose other
than in the interest of the applicant as an Investor Partner
relative to the affairs of the Partnership. The Managing General
Partner may require the Investor Partner requesting the participant
list to represent that the list is not requested for a commercial
purpose unrelated to the Investor Partner's interest in the
Partnership. The remedies provided hereunder to Investor Partners
requesting copies of the participant list are in addition to, and
shall not in any way limit, other remedies available to Investor
Partners under federal law, or the laws of any state.
8.02 Reports. The Managing General Partner shall deliver to each
Investor Partner the following financial statements and reports at the
times indicated below:
(a) Within 75 days after the end of the first six months of
each fiscal year (for such six month period) and within 120 days after the
end of each fiscal year (for such year), financial statements, including
a balance sheet and statements of income, Partners' equity, and cash
flows, all of which shall be prepared in accordance with generally
accepted accounting principles. The annual financial statements shall
be accompanied by (i) a report of an independent certified public
accountant designated by the Managing General Partner stating that an
audit of such financial statements has been made in accordance with
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generally accepted auditing standards and that in its opinion such
financial statements present fairly the financial condition, results
of operations, and cash flow of the Partnership in accordance with
generally accepted accounting principles and (ii) a reconciliation
of such financial statements with the information furnished to the
Investor Partners for federal income tax reporting purposes.
(b) Annually by March 15 of each year, a report containing such
information as may be deemed to enable each Investor Partner to prepare
and file his federal income tax return and any required state income tax
return.
(c) Annually within 120 days after the end of each fiscal year
beginning with the fiscal year ending December 31, 1996 [1997 with
respect to Partnerships designated as "PDC 1997- Limited Partnership"],
(i) a summary of the computations of the total estimated proved oil and
gas reserves of the Partnership as of the end of such fiscal year and
the dollar value thereof at then existing prices and a computation of
each Investor Partner's interest in such value, such reserve
computations to be based upon engineering reports prepared by qualified
independent petroleum engineers, (ii) an estimate of the time required
for the extraction of such proved reserves and the present worth thereof
(discounted at a rate generally accepted in the oil and gas industry and
undiscounted), and (iii) a statement that because of the time period
required to extract such reserves the present value of revenues to be
obtained in the future is less than if such revenues were immediately
receivable. Each such reported shall be prepared in accordance with
customary and generally accepted standards and practices for petroleum
engineers and shall be prepared by a recognized independent petroleum
engineer selected from time to time by the Managing General Partner.
No later than 90 days following the occurrence of an event resulting in
a reduction in an amount of 10% or more of the estimated value of the
proved oil and gas reserves as last reported to the Investor Partners,
other than a reduction resulting from production, a new summary
conforming to the requirements set forth above in this Section 8.02(c)
shall be delivered to the Investor Partners.
(d) Within 75 days after the end of the first six months of
each fiscal year and within 120 days after the end of each fiscal year, (i)
a summary itemization, by type and/or classification, of any transaction
of the Partnership since the date of the last such report with the
Managing General Partner or any Affiliate thereof and the total fees,
compensation, and reimbursement paid by the Partnership (or indirectly
on behalf of the Partnership) to the Managing General Partner and its
Affiliates, and (ii) a schedule reflecting (A) the total costs of the
Partnership (and, where applicable, the costs pertaining to each Lease)
and the costs paid by the Managing General Partner and by the Investor
Partners and (B) the total revenues of the Partnership and the revenues
received by or credited to the accounts of the Managing General Partner
and the Investing Partners. Each semi-annual report delivered by the
Managing General Partner may contain summary estimates of the
information described in subdivision (i) of Section 8.02(c).
(e) Monthly within 15 days after the end of each calendar month
while the Partnership is participating in the drilling and
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completion of wells in which it has an interest until the end of such
activity, and thereafter for a period of three years within 75 days
after the end of the first six months of each fiscal year and within 120
days after the end of each fiscal year, (i) a description of each
Prospect or field in which the Partnership owns Leases including the
cost, location, number of acres under lease, and the interest owned
therein by the program (provided that after the initial description of
each such Prospect or field has been provided to the Investor Partners
only material changes, if any, with respect to such Prospect or field
need be described), (ii) a description of all farmins and farmouts of
the Partnership made since the date of the last such report, including
the reason therefor, the location and timing thereof, the person to whom
made and the terms thereof, and (iii) a summary of the wells drilled by
the Partnership, indicating whether each of such wells has been
completed, a statement of the cost of each well completed or abandoned
and the reason for abandoning any well after commencement of production.
Each report delivered by the Managing General Partner may contain
summary estimates of the information described in subsection (iii).
(f) Such other reports and financial statements as the Managing
General Partner shall determine from time to time.
(g) Concurrently with their transmittal to Investor Partners
and as required, the Managing General Partner shall file a copy of each such
report with the California Commissioner of Corporations and with the
securities divisions of other states.
8.03 Bank Accounts. All funds of the Partnership shall be deposited
in such separate bank account or accounts, short term obligations of the
U.S. Government or its agencies, or other interest-bearing investments and
money market or liquid asset mutual funds as shall be determined by the
Managing General Partner. All withdrawals therefrom shall be made upon
checks signed by the Managing General Partner or any person authorized to
do so by the Managing General Partner.
8.04 Federal Income Tax Elections.
(a) Except as otherwise provided in this Section 8.04, all
elections required or permitted to be made by the Partnership under the
Code shall be made by the Managing General Partner in its sole
discretion. Each Partner agrees to provide the Partnership with all
information necessary to give effect to any election to be made by the
Partnership.
(b) The Partnership shall elect to currently deduct IDC as an
expense for income tax purposes and shall require any partnership, joint
venture, or other arrangement in which it is a party to make such an
election.
ARTICLE IX
Dissolution; Winding-up
9.01 Dissolution.
(a) Except as otherwise provided herein, the retirement,
withdrawal, removal, death, insanity, incapacity, dissolution, or
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bankruptcy of any Investor Partner shall not dissolve the Partnership.
The successor to the rights of such Investor Partner shall have all the
rights of an Investor Partner for the purpose of settling or
administering the estate or affairs of such Investor Partner; provided,
however, that no successor shall become a substituted Investor Partner
except in accordance with Article VII hereof; provided, further, that
upon the withdrawal of an Additional General Partner, the Partnership
shall be dissolved and wound up unless at that time there is at least
one other General Partner, in which event the business of the
Partnership shall continue to be carried on. Neither the expulsion of
any Investor Partner nor the admission or substitution of an Investor
Partner shall work a dissolution of the Partnership. The estate of a
deceased, insane, incompetent, or bankrupt Investor Partner shall be
liable for all his liabilities as an Investor Partner.
(b) The Partnership shall be dissolved upon the earliest to
occur of: (i) the written consent of the Investor Partners owning a
majority of the then-outstanding Units to dissolve and wind up the
affairs of the Partnership; (ii) subject to the provisions of Subsection
(c) below, the retirement, withdrawal, removal, death, adjudication of
insanity or incapacity, or bankruptcy (or, in the case of a corporate
managing general partner, the withdrawal, removal, filing of a
certificate of dissolution, liquidation, or bankruptcy) of the Managing
General Partner; (iii) the sale, forfeiture, or abandonment of all or
substantially all of the Partnership's property; (iv) December 31, 2046;
(v) a dissolution event described in Subsection (a) above; or (vi) any
event causing dissolution of the Partnership under the Act.
(c) In the case of any event described in Subsection (b)(ii)
above, if a successor Managing General Partner is selected by Partners
owning a majority of the then outstanding Units within ninety (90) days
after such 9.01(b)(ii) event, and if such Investor Partners agree,
within such 90 day period to continue the business of the Partnership,
or if the remaining managing general partner, if any, continues the
business of the Partnership, then the Partnership shall not be
dissolved.
(d) If the retirement, withdrawal, removal, death, insanity,
incapacity, dissolution, liquidation, or bankruptcy of any Partner, or
the assignment of a Partner's interest in the Partnership, or the
substitution or admission of a new Partner, shall be deemed under the
Act to cause a dissolution of the Partnership, then, except as provided
in Section 9.01(c), the remaining Partners may, in accordance with the
Act, continue the Partnership business as a new partnership and all such
remaining Partners agree to be bound by the provisions of this
Agreement.
9.02 Liquidation. Upon a dissolution and final termination of the
Partnership, the Managing General Partner, or in the event there is no
Managing General Partner, any other person or entity selected by the
Investor Partners (hereinafter referred to as a "Liquidator") shall cause
the affairs of the Partnership to be wound up and shall take account of
the Partnership's assets (including contributions, if any, of the Managing
General Partner pursuant to Section 3.01(e) herein) and liabilities, and
the assets shall, subject to the provisions of Section 9.03(b) herein, be
liquidated as promptly as is consistent with obtaining the fair market
value thereof, and the proceeds therefrom (which dissolution and
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<PAGE>
liquidation may be accomplished over a period spanning one or more tax
years in the sole discretion of the Managing General Partner or
Liquidator), to the extent sufficient therefor, shall be applied and
distributed in accordance with Section 9.03.
9.03 Winding-up.
(a) Upon the dissolution of the Partnership and winding up of
its affairs, the assets of the Partnership shall be distributed as follows:
(i) all of the Partnership's debts and liabilities to persons
other than the Managing General Partner shall be paid and
discharged;
(ii) all outstanding debts and liabilities to the Managing
General Partner shall be paid and discharged;
(iii) assets shall be distributed to the Partners to the extent
of their positive Capital Account balances, pro rata, in accordance
with such positive Capital Account balances; and
(iv) any assets remaining after the Partners' Capital Accounts
have been reduced to zero pursuant to Section 9.03(c) herein shall
be distributed 80% to the Investor Partners and 20% to the Managing
General Partner.
(b) Distributions pursuant to this Section 9.03 shall be made
in cash or in kind to the Partners, at the election of the Partners.
Notwithstanding the provision of this Section 9.03(b), in no event shall
the Partners reserve the right to take in kind and separately dispose
of their share of production.
(c) Any in kind property distributions to the Investor Partners
shall be made to a liquidating trust or similar entity for the benefit
of the Investor Partners, unless at the time of the distribution:
(1) the Managing General Partner shall offer the individual
Investor Partners the election of receiving in kind property
distributions and the Investor Partners accept such offer after
being advised of the risks associated with such direct ownership;
or
(2) there are alternative arrangements in place which assure
the Investor Partners that they will not, at any time, be
responsible for the operation or disposition of Partnership
properties.
The winding up of the affairs of the Partnership and the distribution
of its assets shall be conducted exclusively by the Managing General
Partner or the Liquidator, who is hereby authorized to do any and all acts
and things authorized by law for these purposes.
ARTICLE X
Power of Attorney
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10.01 Managing General Partner as Attorney-in-Fact. The undersigned
makes, constitutes, and appoints the Managing General Partner the true and
lawful attorney for the undersigned, and in the name, place, and stead of
the undersigned from time to time to make, execute, sign, acknowledge, and
file:
(a) Any notices or certificates as may be required under the
Act and under the laws of any other state or jurisdiction in which the
Partnership shall engage, or seek to engage, to do business and to do
such other acts as are required to constitute the Partnership as a
limited partnership under such laws.
(b) Any amendment to the Agreement pursuant to and which complies
with Section 11.09 herein.
(c) Such certificates, instruments, and documents as may be
required by, or may be appropriate under the laws of any state or other
jurisdiction in which the Partnership is doing or intends to do business
and with the use of the name of the Partnership by the Partnership.
(d) Such certificates, instruments, and documents as may be
required by, or as may be appropriate for the undersigned to comply
with, the laws of any state or other jurisdiction to reflect a change
of name or address of the undersigned.
(e) Such certificates, instruments, and documents as may be
required to be filed with the Department of Interior (including any
bureau, office or other unit thereof, whether in Washington, D.C. or in
the field, or any officer or employee thereof), as well as with any
other federal or state agencies, departments, bureaus, offices, or
authorities and pertaining to (i) any and all offers to lease, leases
(including amendments, modifications, supplements, renewals, and
exchanges thereof) of, or with respect to, any lands under the
jurisdiction of the United States or any state including without
limitation lands within the public domain, and acquired lands, and
provides for the leasing thereof; (ii) all statements of interest and
holdings on behalf of the Partnership or the undersigned; (iii) any
other statements, notices, or communications required or permitted to
be filed or which may hereafter be required or permitted to be filed
under any law, rule, or regulation of the United States, or any state
relating to the leasing of lands for oil or gas exploration or
development; (iv) any request for approval of assignments or transfers
of oil and gas leases, any unitization or pooling agreements and any
other documents relating to lands under the jurisdiction of the United
States or any state; and (v) any other documents or instruments which
said attorney-in-fact in its sole discretion shall determine should be
filed.
(f) Any further document, including furnishing verified copies of
the Agreement and/or excerpts therefrom, which said attorney-in-fact
shall consider necessary or convenient in connection with any of the
foregoing, hereby giving said attorney-in-fact full power and authority
to do and perform each and every act and thing whatsoever requisite and
necessary to be done in and about the foregoing as fully as the
undersigned might and could do if personally present, and hereby
ratifying and confirming all that said attorney-in-fact shall lawfully
do to cause to be done by virtue hereof.
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10.02 Nature as Special Power. The foregoing grant of authority:
(a) is a special Power of Attorney coupled with an interest, is
irrevocable, and shall survive the death of the undersigned;
(b) shall survive the delivery of any assignment by the undersigned
of the whole or any portion of his Units; except that where the assignee
thereof has been approved by the Managing General Partner for admission
to the Partnership as a substitute general or limited Partner as the
case may be, the Power of Attorney shall survive the delivery of such
assignment for the sole purpose of enabling said attorney-in-fact to
execute, acknowledge, and file any instrument necessary to effect such
substitution; and
(c) may be exercised by said attorney-in-fact with full power of
substitution and resubstitution and may be exercised by a listing of all
of the Partners executing any instrument with a single signature of said
attorney-in-fact.
ARTICLE XI
Miscellaneous Provisions
11.01 Liability of Parties. By entering into this Agreement, no party
shall become liable for any other party's obligations relating to any
activities beyond the scope of this Agreement, except as provided by the
Act. If any party suffers, or is held liable for, any loss or liability
of the Partnership which is in excess of that agreed upon herein, such
party shall be indemnified by the other parties, to the extent of their
respective interests in the Partnership, as provided herein.
11.02 Notices. Any notice, payment, demand, or communication required
or permitted to be given by any provision of this Agreement shall be
deemed to have been sufficiently given or served for all purposes if
delivered personally to the party or to an officer of the party to whom
the same is directed or sent by registered or certified mail, postage and
charges prepaid, addressed as follows (or to such other address as the
party shall have furnished in writing in accordance with the provisions of
this Section): If to the Managing General Partner, 103 East Main Street,
Bridgeport, West Virginia 26330; if to an Investor Partner, at such
Investor Partner's address for purposes of notice which is set forth on
Exhibit A attached hereto. Unless otherwise expressly set forth in this
Agreement to the contrary, any such notice shall be deemed to be given on
the date on which the same was deposited in a regularly maintained
receptacle for the deposit of United States mail, addressed and sent as
aforesaid.
11.03 Paragraph Headings. The headings in this Agreement are inserted
for convenience and identification only and are in no way intended to
describe, interpret, define, or limit the scope, extent, or intent of this
Agreement or any provision hereof.
11.04 Severability. Every portion of this Agreement is intended to be
severable. If any term or provision hereof is illegal or invalid by any
reason whatsoever, such illegality or invalidity shall not affect the
validity of the remainder of this Agreement.
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11.05 Sole Agreement. This Agreement constitutes the entire
understanding of the parties hereto with respect to the subject matter
hereof and no amendment, modification, or alteration of the terms hereof
shall be binding unless the same be in writing, dated subsequent to the
date hereof and duly approved and executed by the Managing General Partner
and such percentage of Investor Partners as provided in Section 11.09 of
this Agreement.
11.06 Applicable Law. This Agreement, which shall be governed
exclusively by its terms, is intended to comply with the Code and with the
Act and shall be interpreted consistently therewith.
11.07 Execution in Counterparts. This Agreement may be executed in any
number of counterparts with the same effect as if all parties hereto had
all signed the same document. All counterparts shall be construed
together and shall constitute one agreement.
11.08 Waiver of Action for Partition. Each of the parties irrevocably
waives, during the term of the Partnership, any right that it may have to
maintain any action for partition with respect to the Partnership and the
property of the Partnership.
11.09 Amendments.
(a) Unless otherwise specifically herein provided, this
Agreement shall not be amended without the consent of the Investor
Partners owning a majority of the then outstanding Units entitled to vote.
(b) The Managing General Partner may, without notice to, or
consent of, any Investor Partner, amend any provisions of these
Articles, or consent to and execute any amendment to these Articles, to
reflect:
(i) A change in the name or location of the principal place of
business of the Partnership;
(ii) The admission of substituted or additional Investor
Partners in accordance with these Articles;
(iii) A reduction in, return of, or withdrawal of, all or a
portion of any Investor Partner's Capital Contribution;
(iv) A correction of any typographical error or omission;
(v) A change which is necessary in order to qualify the
Partnership as a limited partnership under the laws of any other
state or which is necessary or advisable, in the opinion of the
Managing General Partner, to ensure that the Partnership will be
treated as a partnership and not as an association taxable as a
corporation for federal income tax purposes;
(vi) A change in the allocation provisions, in accordance with
the provisions of Section 3.02(l) herein, in a manner that, in the
sole opinion of the Managing General Partner (which opinion shall be
determinative), would result in the most favorable aggregate
consequences to the Investor
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Partners as nearly as possible consistent with the allocations
contained herein, for such allocations to be recognized for federal
income tax purposes due to developments in the federal income tax
laws or otherwise; or
(vii) Any other amendment similar to the foregoing;
provided, however, that the Managing General Partner shall have no
authority, right, or power under this Section to amend the voting
rights of the Investor Partners.
11.10 Consent to Allocations and Distributions. The methods herein set
forth by which allocations and distributions are made and apportioned are
hereby expressly consented to by each Partner as an express condition to
becoming a Partner.
11.11 Ratification. The Investor Partner whose signature appears at
the end of this Article hereby specifically adopts and approves every
provision of this Agreement to which the signature page is attached.
11.12 Substitution of Signature Pages. This Agreement has been
executed in duplicate by the undersigned Investor Partners and one
executed copy of the signature page is attached to the undersigned's copy
of this Agreement. It is agreed that the other executed copy of such
signature page may be attached to an identical copy of this Agreement
together with the signature pages from counterpart Agreements which may be
executed by other Investor Partners.
11.13 Incorporation by Reference. Every exhibit, schedule, and other
appendix attached to this Agreement and referred to herein is hereby
incorporated in this Agreement by reference.
* * * * *
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SIGNATURE PAGE
IN WITNESS WHEREOF, the undersigned have executed this Agreement as of
the day and year first written above.
MANAGING GENERAL PARTNER: INITIAL LIMITED PARTNER:
Petroleum Development Corporation
103 East Main Street
Bridgeport, West Virginia 26330
Steven R. Williams
103 East Main Street Inc.
Bridgeport, West Virginia 26330
By:________________________________
Steven R. Williams
President
INVESTOR PARTNERS
COMPLETE TO INVEST AS ADDITIONAL GENERAL PARTNER
ADDITIONAL GENERAL PARTNER(S):
NUMBER OF UNITS Name:__________________________________
PURCHASED (Print Name)
___________________ ______________________________________
(Signature)
SUBSCRIPTION PRICE
$__________________ Address:_______________________________
______________________________________________________________________
By: Petroleum Development Corporation
By: __________________________________
its ______________________________
Attorney-in-Fact
COMPLETE TO INVEST AS LIMITED PARTNER
LIMITED PARTNER(S):
NUMBER OF UNITS
Name:__________________________________
PURCHASED (Print Name)
______________________________________
(Signature)
SUBSCRIPTION PRICE
$__________________
Address:_______________________________
_______________________________________
54
<PAGE>
By: Petroleum Development Corporation
By: __________________________________
its______________________________
Attorney-in-Fact
55
<PAGE>
EXHIBIT A
TO
AGREEMENT OF LIMITED PARTNERSHIP
OF
PDC 1996-___ LIMITED PARTNERSHIP,
[PDC 1997-___ LIMITED PARTNERSHIP,]
A WEST VIRGINIA LIMITED PARTNERSHIP
Number of
Names and Addresses of Investors Nature of Interest
Units
56
<PAGE>
APPENDIX B TO PROSPECTUS
SUBSCRIPTION AGREEMENT
PDC 1996-_ Limited Partnership
[PDC 1997-_ Limited Partnership]
I hereby agree to purchase ______ Unit(s) in the PDC 1996-_ Limited
Partnership [PDC 1997-_ Limited Partnership] (the "Partnership") at
$20,000 per Unit. Enclosed please find my check in the amount of
$________. My completion and execution of this Subscription Agreement
also constitutes my execution of the Limited Partnership Agreement and the
Certificate of Limited Partnership of the Partnership. If this
Subscription is accepted, I agree to be bound and governed by the
provisions of the Limited Partnership Agreement of the Partnership. With
respect to this purchase, being aware that a broker may sell to me only if
I qualify according to the express standards stated herein and in the
Prospectus, I represent that:
(a) I have received a copy of the Prospectus for the Partnership.
(b) I have a net worth of not less than $225,000 (exclusive of home,
furnishings and automobiles); or I have a net worth of not less than
$60,000 (exclusive of home, furnishings and automobiles) and had during my
last tax year or estimate that I will have 1996 [1997] taxable income as
defined in Section 63 of the Internal Revenue Code of 1986 of at least
$60,000, without regard to an investment in the Partnership.
(c) If a resident of Alabama, Arizona, Arkansas, California,
Indiana, Iowa, Kansas, Kentucky, Maine, Massachusetts, Michigan, Minnesota,
Mississippi, Missouri, New Hampshire, New Mexico, North Carolina, Ohio,
Oklahoma, Oregon, Pennsylvania, South Dakota, Tennessee, Texas, Vermont,
Washington, or Wisconsin, I am aware of and satisfy the additional
suitability and other requirements stated in Appendix C to the Prospectus.
(d) If a resident of California, I acknowledge and understand that
the offering may not comply with all the rules set forth in Title 10 of
the California Administrative Code; the following are some, but not
necessarily all, of the possible deviations from the California rules:
Program selling expenses may exceed the established limit; and the
compensation formula varies from the California rules. Even in light of
such non-compliance, I affirmatively state that I still want to invest in
the Partnership.
(e) Except as set forth in (f) below, I am purchasing Units for my
own account.
(f) If a fiduciary, I am purchasing for a person or entity having
the appropriate income and/or net worth specified in (c) or (d) above.
(g) I certify that the number shown as my Social Security or Taxpayer
Identification Number on the signature page is correct.
The above representations do not constitute a waiver of any rights that
I may have under the Acts administered by the Securities and Exchange
Commission or by any state regulatory agency administering statutes
bearing on the sale of securities.
<PAGE>
(i) The purchase of Units as an Additional General Partner
involves a risk of unlimited liability to the extent that the
Partnership's liabilities exceed its insurance proceeds, the Partnership's
assets, and indemnification by the Managing General Partner, as described
in "Risk Factors" in the Prospectus.
(ii) The NASD requires the Soliciting Dealer or registered
representative to inform potential investors of all pertinent facts
relating to the liquidity and marketability of the Units, including the
following: (i) the risks involved in the offering, including the
speculative nature of the investment and the speculative nature of
drilling for oil and gas; (ii) the financial hazards involved in the
offering, including the risk of losing my entire investment; (iii) the
lack of liquidity of this investment; (iv) the restrictions of
transferability of the Units; and (v) the tax consequences of the
investment.
Investors are required to execute their own subscription agreements.
The Managing General Partner will not accept any subscription agreement
that has been executed by someone other than the investor or in the case
of fiduciary accounts by someone who does not have the legal power of
attorney to sign on the investor's behalf.
The Managing General Partner may not complete a sale of Units to an
investor until at least five business days after the date the investor
receives a final prospectus. In addition, the Managing General Partner
will send each investor a confirmation of purchase.
Signature and Power of Attorney
I hereby appoint Petroleum Development Corporation, with full power of
substitution, my true and lawful attorney to execute, file, swear to and
record any Certificate(s) of Limited Partnership or amendments thereto
(including but not limited to any amendments filed for the purpose of the
admission of any substituted Partners) or cancellation thereof, including
any other instruments which may be required by law in any jurisdiction to
permit qualification of the Partnership as a limited partnership or for
any other purpose necessary to implement the Limited Partnership
Agreement, and as more fully described in Article X of the Limited
Partnership Agreement.
If a resident of California, I am aware of and satisfy the additional
suitability requirements stated in Appendix C to the Prospectus and
acknowledge the receipt of California Rule 260.141.11 at pages C-2, C-3,
C-4 and C-5 of Appendix C to the Prospectus.
Date: _________________, 199__.
__________________________ _____________________________
Signature Signature
__________________________ _____________________________
Please Print Name Please Print Name
__________________________ ______________________________
Social Security or Tax Social Security or Tax
Identification Number Identification Number
B-2
<PAGE>
I utilize the calendar year as my Federal income tax year, unless
indicated otherwise as follows: _________________________.
Mailing Address:
________________________________________________________________________
Street
____________________ ______________________________ ____________
City State
Zip Code
Address for Distributions and Notices, if different from above:
________________________________________________________________________
Street
_________________________________________________________________________
City State Zip Code (Account or
Reference No.)
Business Telephone No. ( ) _________ Home Telephone No. ( ) __________
Type of Units Purchased:
IF NO SELECTION IS MADE, THE
PARTNERSHIP CANNOT ACCEPT YOUR
SUBSCRIPTION AND WILL HAVE TO [ ] Units as an Additional General Partner
SUBSCRIPTION AND WILL HAVE TO [ ] Units as a Limited Partner
RETURN THIS SUBSCRIPTION AGREEMENT
AND YOUR MONEY TO YOU.
Title to Units to be held:
[ ] Individual Ownership [ ] Tenants in Common (both
[ ] Joint Tenants with Right (both persons must sign)
of Survivorship [ ] Other _______________
(both persons must sign)
TO BE COMPLETED BY PETROLEUM DEVELOPMENT CORPORATION
Petroleum Development Corporation, as the Managing General Partner of
the Partnership, hereby accepts this Subscription and agrees to hold and
invest the same pursuant to the terms and conditions of the Limited
Partnership Agreement of the Partnership.
ATTEST: PETROLEUM DEVELOPMENT CORPORATION
By:____________________________ _______________________________
Secretary
Title:_________________________
Date:__________________________
B-3
<PAGE>
TO BE COMPLETED BY REGISTERED REPRESENTATIVE
(For Commission and Other Purposes)
I hereby represent that I have discharged my affirmative obligations
under Sections 3(b) and 4(d) of Appendix F to the NASD's Rules of Fair
Practice and specifically have obtained information from the above-named
subscriber concerning his/her net worth, annual income, federal income tax
bracket, investment portfolio and other financial information and have
determined that an investment in the Partnership is suitable for such
subscriber, that such subscriber is or will be in a financial position to
realize the benefits of this investment, and that such subscriber has a
fair market net worth sufficient to sustain the risks for this investment.
I have also informed the subscriber of all pertinent facts relating to the
liquidity and marketability of an investment in the Partnership, of the
risks of unlimited liability regarding an investment as an Additional
General Partner, and of the passive loss limitations for tax purposes of
an investment as a Limited Partner.
______________________________
____________________________________
Name of Brokerage Firm Office Number FC RR AE Number
________________________________
____________________________________
Registered Representative Office Address FC RR AE Name (Please Print)
____________________________________
City State Zip Code FC RR AE Social Security
Number
_______________________________,199_
Area Code Telephone Number FC RR AE Signature Date
B-3
<PAGE>
APPENDIX C TO PROSPECTUS
PDC 1996-1997 DRILLING PROGRAM
SPECIAL SUBSCRIPTION INSTRUCTIONS
Checks for Units should be made payable to "PNC Bank, N.A. as Escrow
Agent for PDC 1996-_ Limited Partnership [PDC 1997-_ Limited Partnership]"
and should be given to the subscriber's broker for submission to the
Dealer Manager and Escrow Agent. The minimum subscription is $5,000.
Subscriptions are payable only in cash upon subscription. In the event
that a subscriber purchases Units in a particular Partnership on more than
one occasion during an offering period, the minimum purchase on each
occasion is $5,000 (one-quarter Unit).
Signature Requirement.
- Investors are required to execute their own subscription agreements.
The Managing General Partner will not accept any subscription
agreement that has been executed by someone other than the investor
or in the case of fiduciary accounts someone who does not have the
legal power of attorney to sign on the investor's behalf.
Transfer of Units by Missouri Residents.
- The Commissioner of Securities of Missouri classifies the securities
(the Units) as being ineligible for any transactional exemption
under the Missouri Uniform Securities Act (Section 409.402(b), RsMo.
1969). Therefore, unless the securities are again registered, the
offer for sale or resale thereof in the State of Missouri may be
subject to the sanctions of the Act.
Subscribers of Limited Partnership Interests:
- If a New Hampshire resident, I have either: (1) a net worth of not
less than $250,000 (exclusive of home, furnishings, and
automobiles), or (2) a net worth of not less than $125,000
(exclusive of home, furnishings and automobiles), $50,000 in income,
and some portion of my estimated taxable income for the current year
will be subject to federal income tax at a rate of not less than
31%.
- If a North Carolina resident, I have either: (1) a net worth of not
less than $225,000 (exclusive of home, furnishings and automobiles),
or (2) a net worth of not less than $60,000 (exclusive of home,
furnishings and automobiles) and estimated 1996 for Partnerships
designated "PDC 1996-_ Limited Partnership" and 1997 for
Partnerships designated "PDC 1997-_ Limited Partnership" taxable
income as defined in Section 63 of the Internal Revenue Code of 1986
of $60,000 or more without regard to an investment in a Partnership.
- If a Pennsylvania resident, I have either: (1) a net worth of at
least $225,000 (exclusive of home, furnishings and automobiles) or
(2) a net worth of at least $60,000 (exclusive of home, furnishings
and automobiles) and a taxable income in 1995 for Partnerships
designated "PDC 1996-_ Limited Partnership" and 1996 for
Partnerships designated "PDC 1997-_ Limited Partnership" of $60,000
or estimate that I will have an annual taxable income of $60,000
during my current tax year; or that I am purchasing in a fiduciary
capacity for a person or entity having such net worth or such
taxable income. My investment in the Partnership will not be equal
to or more than 10% of my net worth.<PAGE>
Additional General Partner
Subscribers:
- If a resident of Alabama, Arizona, Arkansas, Indiana, Iowa, Kansas,
Kentucky, Maine, Massachusetts, Michigan, Minnesota, Mississippi,
Missouri, New Mexico, North Carolina, Ohio, Oklahoma, Oregon,
Pennsylvania, South Dakota, Tennessee, Texas, Vermont, or Wisconsin,
I (i) have an individual or joint minimum net worth with my spouse
of $225,000 or more, without regard to the investment in the
program, (exclusive of home, home furnishings and automobiles) and
a combined minimum gross income of $100,000 ($120,000 for Arizona
residents) or more for the current year and for the two previous
years; or (ii) have an individual or joint minimum net worth with my
spouse in excess of $1,000,000, inclusive of home, home furnishings
and automobiles; or (iii) have an individual or joint minimum net
worth with my spouse in excess of $500,000, exclusive of home, home
furnishings and automobiles; or (iv) have a combined minimum gross
income of $200,000 in the current year and the two previous years.
If I am a Pennsylvania resident, my investment in the Partnership
will not be equal to or more than 10% of my net worth.
- If resident of Washington, I (i) have net worth, or a joint net
worth with my spouse, of not less than $1,000,000 at the time of the
purchase or (ii) have an individual income in excess of $200,000 in
each of the two most recent years or joint income with my spouse in
excess of $300,000 in each of those years and have a reasonable
expectation of reaching the same income level in the current year.
ATTENTION CALIFORNIA INVESTORS
- A resident of California who subscribes for Units of general
partnership interest must represent that he (i) has a net worth of
not less than $250,000 (exclusive of home, furnishings and
automobiles) and had annual gross income during 1995 for
Partnerships designated "PDC 1996-_ Limited Partnership" and 1996
for Partnerships designated "PDC 1997-_ Limited Partnership" of
$120,000 or more, or expects to have gross income in 1996 for
Partnerships designated "PDC 1996-_ Limited Partnership" and 1997
for Partnerships designated "PDC 1997-_ Limited Partnership" of
$120,000 or more, or (ii) has a net worth of not less than $500,000
(exclusive of home, furnishings and automobiles), or (iii) has a net
worth of not less than $1,000,000, or (iv) expects to have gross
income in 1996 for Partnerships designated "PDC 1996-_ Limited
Partnership" and 1997 for Partnerships designated "PDC 1997-_
Limited Partnership" of not less than $200,000.
- A resident of California who subscribes for Units of limited
partnership interest must represent that he (1) has a net worth of
not less than $250,000 (exclusive of home, furnishings and
automobiles) and expects to have gross income in 1996 for
Partnerships designated "PDC 1996-_ Limited Partnership and 1997 for
Partnerships designated "PDC 1997-_ Limited Partnership" of $65,000
or more, or (2) has net worth of not less than $500,000 (exclusive
of home, furnishings and automobiles), or (3) has a net worth of not
less than $1,000,000, or (4) expects to have gross income in 1996
for Partnerships designated "PDC 1996-_ Limited Partnership" and
1997 for Partnerships designated "PDC 1997-_ Limited Partnership" of
not less than $200,000.
C-2
<PAGE>
- If a resident of California, I am aware that:
IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY, OR
ANY INTEREST THEREIN, OR TO RECEIVE ANY CONSIDERATION THEREFOR,
WITHOUT THE PRIOR WRITTEN CONSENT OF THE COMMISSIONER OF
CORPORATIONS OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED IN THE
COMMISSIONER'S RULES.
As a condition of qualification of the Units for sale in the State of
California, the following rule is hereby delivered to each California
purchaser.
California Administrative Code, Title 10, CH. 3, Rule 260.141.11.
Restriction on transfer. (a) The issuer of a security upon which a
restriction on transfer has been imposed pursuant to Sections 260.102.6,
260.102.141.10, and 260.534.10 shall cause a copy of this Section to be
delivered to each issuee or transferee of such security at the time the
certificate evidencing the security is delivered to the issuee or
transferee.
(b) It is unlawful for the holder of any such security to consummate
a sale or transfer of such security, or any interest therein, without the
prior written consent of the Commissioner (until this condition is removed
pursuant to Section 260.141.12 of these rules), except:
(1) to the issuer;
(2) pursuant to the order or process of any court;
(3) to any person described in Subdivision (i) of Section
25102 of the Code or Section 260.105.14 of these rules;
(4) to the transferor's ancestors, descendants or spouse, or
any custodian or trustee for the account of the transferor's ancestors,
descendants, or spouse; or to a transferee by a trustee or custodian
for the account of the transferee or the transferee's ancestors,
descendants or spouse;
(5) to the holders of securities of the same class of the same
issuer;
(6) by way of gift or donation intervivos or on death;
(7) by or through a broker-dealer licensed under the Code
(either acting as such or as a finder) to a resident of a foreign state,
territory or country who is neither domiciled in this state to the
knowledge of the broker-dealer, nor actually present in this state if
the sale of such securities is not in violation of any securities law
of the foreign state, territory or country concerned;
(8) to a broker-dealer licensed under the Code in a principal
transaction, or as an underwriter or member of an underwriting
syndicate or selling group;
(9) if the interest sold or transferred is a pledge or other
lien given by the purchaser to the seller upon a sale of the security for
which the Commissioner's written consent is obtained or under this rule
not required;
C-3
<PAGE>
(10) by way of a sale qualified under Section 25111, 25112,
25113
or 25121 of the Code, of the securities to be transferred, provided
that no order under Section 25140 or Subdivision (a) of Section 25143
is in effect with respect to such qualification;
(11) by a corporation to a wholly-owned subsidiary of such
corporation, or by a wholly-owned subsidiary of a corporation to such
corporation;
(12) by way of an exchange qualified under Section 25111, 25112
or 25113 of the Code, provided that no order under Section 25140 or
Subdivision (a) of Section 25143 is in effect with respect to such
qualification;
(13) between residents of foreign states, territories or
countries who are neither domiciled nor actually present in this state;
(14) to the State Controller pursuant to the Unclaimed Property
Law or to the administrator of the unclaimed property law of another
state;
(15) by the State Controller pursuant to the Unclaimed Property
Law or by the administrator of the unclaimed property law of another
state if, in either such case, such person (i) discloses to potential
purchasers at the sale that transfer of the securities is restricted
under this rule, (ii) delivers to each purchaser a copy of this rule,
and (iii) advises the Commissioner of the name of each purchaser; or
(16) by a trustee to a successor trustee when such transfer
does not involve a change in the beneficial ownership of the securities;
provided that any such transfer is on the condition that any certificate
evidencing the security issued to such transferee shall contain the legend
required by this section.
(c) The certificates representing all such securities subject to
such a restriction on transfer, whether upon initial issuance or upon any
transfer thereof, shall bear on their face a legend, prominently stamped
or printed thereon in capital letters of not less than 10-point size,
reading as follows:
"IT IS UNLAWFUL TO CONSUMMATE A SALE OR TRANSFER OF THIS SECURITY,
OR ANY INTEREST THEREIN, OR TO RECEIVE ANY CONSIDERATION THEREFOR,
WITHOUT THE PRIOR WRITTEN CONSENT OF THE COMMISSIONER OF CORPORATIONS
OF THE STATE OF CALIFORNIA, EXCEPT AS PERMITTED IN THE COMMISSIONER'S
RULES."
As a condition of qualification of the Units for sale in the State of
California, each California subscriber through the execution of the
Subscription Agreement acknowledges his understanding that the California
Department of Corporations has adopted certain regulations and guidelines
which apply to oil and gas interests offered to the public in the State of
California.
C-4
<PAGE>
FEDERAL AND STATE TAX TABLES
Table 1 - Federal Taxes
<TABLE>
<S> <S> <S> <S> <S>
Head Married Married
of Individual Joint Marginal
Household Single Return Return Tax Rate
0 to 0 to 0 to 0 to
$31,250 $23,500 $19,500 $39,500 15.0%
$31,250 to $23,500 to $19,500 to $39,500 to
$80,750 $56,550 $47,125 $94,250 28.0%
$80,750 to $56,550 to $47,125 to $94,2500 to
$130,800 $117,950 $71,800 $143,600 31.0%
$130,800 to $117,950 to $71,800 to $143,600 to
$256,500 $256,500 $128,250 $256,500 36.0%
$256,500 $256,500 $128,520 $256,500 39.6%
</TABLE>
Source: 1995 Research Institute of America ("RIA") Federal Tax Handbook;
IRC Section 1(a) - Federal Tax Rates.
Table 2 - State Income Taxes
<TABLE>
<S> <S> <S> <S> <S> <S>
Federal Federal
Income Income Top
Used As Top State Used As State
State Tax Tax State Tax Tax
State Base Rate State Base Rate
Alabama No 5.0% Missouri Yes 6.0%
Arizona Yes 6.9% Montana Yes 11.0%
Arkansas No 7.0% Nebraska Yes 6.99%
California Yes 11.0% New Hampshire No 5.0%
Colorado Yes 5.0% New Jersey No 6.65%
Connecticut Yes 4.5% New Mexico Yes 8.5%
Delaware Yes 7.7% New York Yes 7.875%
D.C. Yes 9.5% North Carolina Yes 7.75%
Georgia Yes 6.0% North Dakota Yes 12.0%
Hawaii Yes 10.0% Ohio Yes 7.5%
Idaho Yes 8.2% Oklahoma Yes 7.0%
Illinois Yes 3.0% Oregon Yes 9.0%
Indiana Yes 3.4% Pennsylvania No 2.8%
Iowa Yes 9.98% Rhode Island Yes 10.89%*
Kansas Yes 6.45% South Carolina Yes 7.0%
Kentucky Yes 6.0% Tennessee No 6.0%
Louisiana Yes 6.0% Utah Yes 7.2%
Maine Yes 8.5% Vermont Yes 9.9%**
Maryland Yes 8.0% Virginia Yes 5.75%
Massachusetts Yes 12.0% West Virginia Yes 6.5%
Michigan Yes 4.4% Wisconsin Yes 6.93%
Minnesota Yes 8.5% *27.5% of Federal Tax
Mississippi No 5.0% **25.0% of Federal Tax
No personal income tax in: Alaska, Florida, Nevada, South Dakota, Texas,
Washington, and Wyoming.
+ Maryland state tax is 5% plus county tax = 8% maximum Maryland state
income tax.
</TABLE>
Source: 1995 RIA All States Tax Handbook.
C-5<PAGE>
Table 3 - Self-Employment Tax
<TABLE>
<S> <S>
Medicare portion of self-employment tax 2.9%
Self-employment tax rate for those
with self-employment income
below the threshold ($61,200 for 1995) 12.4%
Total self-employment tax rate for those
with self-employment income below $61,200 15.3%
</TABLE>
For self-employment tax purposes, losses from one business may offset the
income of another. Self-employed individuals might be able to use an
investment as an Additional General Partner in the Program to lower their
self-employment tax. Self-employed individuals who are Additional General
Partner might be able to realize additional tax savings, since deductions
from the Program might be used to reduce self-employment income of
Additional General Partners for tax purposes. If total self-employment
income is above $61,200, the reduction would be 2.9% of the amount
deducted (the Medicare tax). Below $61,200, the savings would be 15.3% of
the amount deducted. Married couples with one self-employed partner may
wish to invest in the name of the self-employed partner to maximize the
tax benefit.
C-6
<PAGE>
APPENDIX D TO THE PROSPECTUS
METZGER, HOLLIS, GORDON & MORTIMER
1275 K Street, NW
Washington, DC 20005
June 30, 1995
Petroleum Development Corporation
103 East Main Street
Bridgeport, West Virginia 26330
Re: PDC 1996-1997 Drilling Program
Dear Sirs:
We have acted as counsel for PDC 1996-1997 Drilling Program, in
connection with the offer and sale of securities (the "Units") in a series
of limited partnerships, PDC 1996-A Limited Partnership, PDC 1996-B
Limited Partnership, PDC 1996-C Limited Partnership, PDC 1996-D Limited
Partnership, PDC 1997-A Limited Partnership, PDC 1997-B Limited
Partnership, PDC 1997-C Limited Partnership, and PDC 1997-D Limited
Partnership (the "Partnerships") to be organized as limited partnerships
under the West Virginia Uniform Limited Partnership Act and in connection
with the preparation and filing of a registration statement on Form S-1
(the "Registration Statement"). Capitalized terms used herein shall have
the meaning ascribed to such terms in the Registration Statement, unless
otherwise provided.
We have examined and are familiar with: (i) the Registration Statement,
including a prospectus (the "Prospectus"), (ii) the Partnerships' form of
limited partnership agreement (the "Partnership Agreement"), and (iii)
such other documents and instruments as we have considered necessary for
purposes of the opinions hereinafter set forth.
In our examination we have assumed the authenticity of original
documents, the accuracy of copies and the genuineness of signatures. We
have relied upon the representations and statements of the Managing
General Partner of the Partnerships and its affiliates with respect to the
factual determinations underlying the legal conclusions set forth herein,
including a representation of Petroleum Development Corporation as to its
net worth. We have not attempted to verify independently such
representations and statements.
Please note that we are opining only as to the matters expressly set
forth herein, and no opinion should be inferred as to any other matters.
We are unable to render opinions as to a number of federal income tax
issues relating to an investment in Units and the operations of the
Partnerships. Finally, we are not expressing any opinion with respect to
the amount of allowable losses or credits that may be generated by the<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-2
Partnerships or the amount of each Investor Partner's share of allowable
losses or credits from the Partnerships' activities.
This Appendix D to the Prospectus constitutes our opinion as to all
material tax considerations of the offering. In our opinion, each of the
legal conclusions rendered in this Appendix D to the Prospectus is correct
in all material respects as of the date of this opinion, under the
Internal Revenue Code of 1986, as amended, the rules and regulations
promulgated thereunder, and existing interpretations thereof.
The following opinion and statements are based upon the provisions of
the Internal Revenue Code of 1986, as amended (the "Code"), including
revisions to the Code effected by the Revenue Reconciliation Act of 1990
(the "1990 Act"), which was enacted into law on November 5, 1990, the
Omnibus Budget Reconciliation Act of 1990, the Energy Policy Act of 1992
(the "Energy Act"), the Revenue Reconciliation Act of 1993 (the "RRA 93"),
enacted into law on August 10, 1993, and the Uruguay Round Agreements Act
("GATT"), enacted into law on December 8, 1994, existing and proposed
regulations thereunder, current administrative rulings, and court
decisions. The federal income tax law is uncertain as to many of the tax
matters material to an investment in the Partnership, and it is not
possible to predict with certainty how the law will develop or how the
courts will decide various issues if they are litigated. While this
opinion fairly states our views as Counsel concerning the tax aspects of
an investment in the Partnership, both the Service and the courts may
disagree with our position on certain issues.
Moreover, uncertainty exists concerning some of the federal income tax
aspects of the transactions being undertaken by the Partnership. Some of
the tax positions being taken by the Partnership may be challenged by the
Internal Revenue Service (the "Service") and there is no assurance that
any such challenge will not be successful. Thus, there can be no
assurance that all of the anticipated tax benefits of an investment in the
partnership will be realized.
Our opinions are based upon the transactions described in the
Prospectus (the "Transaction") and upon facts as they have been
represented to us or determined by us as of the date of the opinion. Any
alteration of the facts may adversely affect the opinions rendered. In
our opinion, the preponderance of the material tax benefits, in the
aggregate, will be realized by the Investor Partners. It is possible,
however, that some of the tax benefits will be eliminated or deferred to
future years.
Because of the factual nature of the inquiry, and in certain cases the
lack of clear authority in the law, it is not possible to reach a judgment
as to the outcome on the merits (either favorable or unfavorable) of
certain material federal income tax issues as described more fully herein.
SUMMARY OF CONCLUSIONS
Opinions expressed: The following is a summary of the specific
opinions expressed by us with respect to Tax Considerations discussed
herein. TO BE FULLY UNDERSTOOD, THE COMPLETE DISCUSSION OF THESE MATTERS
SHOULD BE READ BY EACH PROSPECTIVE INVESTOR PARTNER.<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-3
1. The material federal income tax benefits in the aggregate from an
investment in the Partnership will be realized.
2. The Partnership will be treated as a partnership for federal income
tax purposes and not as a corporation and not as an association taxable as
a corporation.
3. To the extent the Partnership's wells are timely drilled and amounts
are timely paid, the Partners will be entitled to their pro rata share of
the Partnership's IDC paid in 1996, with respect to Partnerships
designated "PDC 1996-_ Limited Partnership", and 1997 with respect to
Partnerships designated "PDC 1997-_ Limited Partnership."
4. Neither the at risk nor the adjusted basis rules will limit the
deductibility of losses generated from the Partnership.
5. Additional General Partners' interests will not be considered a
passive activity within the meaning of Code Section 469 and losses
generated while such general partner interest is so held will not be
limited by the passive activity provisions.
6. Limited Partners' interests (other than those held by Additional
General Partners who convert their interests into Limited Partners'
interests) will be considered a passive activity within the meaning of
Code Section 469 and losses generated therefrom will be limited by the
passive activity provisions.
7. The Partnership will not be terminated solely as the result of the
conversion of Partnership interests.
8. To the extent provided herein, the Partners' distributive shares of
Partnership tax items will be determined and allocated substantially in
accordance with the terms of the Partnership Agreement.
9. The Partnership will not be required to register with the Service as
a tax shelter.
No opinion expressed: Due to the lack of authority, or the essentially
factual nature of the question, we express no opinion on the following:
1. The impact of an investment in the Partnership on an Investor's
alternative minimum tax, due to the factual nature of the issue.
2. Whether, under Code Section 183, the losses of the Partnership will
be treated as derived from "activities not engaged in for profit," and
therefore nondeductible from other gross income, due to the inherently
factual nature of a Partner's interest and motive in engaging in the
Transaction.
3. Whether each Partner will be entitled to percentage depletion since
such a determination is dependent upon the status of the Partner as an <PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-4
independent producer. Due to the inherently factual nature of such a
determination, counsel is unable to render an opinion as to the
availability of percentage depletion.
4. Whether any interest incurred by a Partner with respect to any
borrowings will be deductible or subject to limitations on deductibility,
due to the factual nature of the issue. Without any assistance of the
Managing General Partner or any of its affiliates, some Partners may
choose to borrow the funds necessary to acquire a Unit and may incur
interest expense in connection with those loans. Based upon the purely
factual nature of any such loans, we are unable to express an opinion with
respect to the deductibility of any interest paid or incurred thereon.
5. Whether the fees to be paid to the Managing General Partner and to
third parties will be deductible, due to the factual nature of the issue.
Due to the inherently factual nature of the proper allocation of expenses
among nondeductible syndication expenses, amortizable organization
expenses, amortizable "start-up" expenditures, and currently deductible
items, and because the issues involve questions concerning both the nature
of the services performed and to be performed and the reasonableness of
amounts charged, we are unable to express an opinion regarding such
treatment.
General Information: Certain matters contained herein are not
considered to address a material tax consequence and are for general
information, including the matters contained in sections dealing with gain
or loss on the sale of Units or of property, Partnership distributions,
tax audits, penalties, and state, local, and self-employment tax.
Our opinions are also based upon the facts described in this Prospectus
and upon certain representations made to us by the Managing General
Partner for the purpose of permitting us to render our opinions, including
the following representations with respect to the Program:
1. The Partnership Agreement to be entered into by and among the Managing
General Partner and Investor Partners and any amendments thereto will
be duly executed and will be made available to any Investor Partner
upon written request. The Partnership Agreement will be duly recorded
in all places required under the West Virginia Uniform Limited
Partnership Act (the "Act") for the due formation of the Partnership
and for the continuation thereof in accordance with the terms of the
Partnership Agreement. The Partnership will at all times be operated
in accordance with the terms of the Partnership Agreement, the
Prospectus, and the Act.
2. No election will be made by the Partnership, Investor Partners, or
Managing General Partner to be excluded from the application of the
provisions of Subchapter K of the Code.
<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-5
3. The Partnership will own an operating mineral interest, as defined in
the Code and in the Regulations, in all of the Drill Sites and none of
the Partnership's revenues will be from non-working interests.
4. The Investor Partners will not own, directly or indirectly,
individually or in the aggregate, more than twenty percent (20%) of the
shares of the Managing General Partner, or of any affiliate (as that
term is defined in Code Section 1504(a) and determined by application
of the attribution rules of Code Section 318).
5. The Managing General Partner will be independent of the Investor
Partners and will not be merely a "dummy" acting as an agent for the
Investor Partners. The Managing General Partner has and will continue
to have at all times during the existence of the Partnership a net
worth in excess of $5,000,000 (excluding its interest in the
Partnership or any other limited partnership).
6. The respective amounts that will be paid to the General Partners as
Drilling Fees, Operating Fees, and other fees will be amounts that
would not exceed amounts that would be ordinarily paid for similar
transactions between Persons having no affiliation and dealing with
each other at "arms' length."
7. The Managing General Partner will cause the Partnership to properly
elect to deduct currently all Intangible Drilling and Development
Costs.
8. The Partnership will have a December 31 taxable year and will report
its income on the accrual basis.
9. The Drilling Agreement to be entered into by and among the Managing
General Partner and the Partnership will be duly executed and will
govern the drilling of the Partnership's Wells. All Partnership wells
will be spudded by not later than March 30, 1997 with respect to
Partnerships designated "PDC 1996-_ Limited Partnership" and March 30,
1998 with respect to Partnerships designated "PDC 1997-_ Limited
Partnership." The entire amount to be paid to the Managing General
Partner under the Operating Agreement is attributable to Intangible
Drilling and Development Costs and does not include a profit for
services performed or materials provided by third parties which are
passed through at actual cost.
10. The Operating Agreement will be duly executed and will govern the
operation of the Partnership's Wells.
11. Based upon the Managing General Partner's review of its experience
with its previous drilling programs for the past several years and
upon the intended operations of the Partnership, the Managing
General Partner believes that the sum of (i) the aggregate
deductions, including depletion deductions, and (ii) 350 percent of
the aggregate
<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-6
credits from the Partnership will not, as of the close of any of the
first five years ending after the date on which Units are offered
for sale, exceed two times the cash invested by the Partners in the
Partnership as of such dates. In that regard, the Managing General
Partner has reviewed the economics of its similar oil and gas
drilling programs for the past several years, and has represented
that it has determined that none of those programs has resulted in
a tax shelter ratio greater than two to one. Further, the Managing
General Partner has represented that the deductions and credits that
are or will be represented as potentially allowable to an investor
will not result in any Partnership having a tax shelter ratio
greater than two to one and believes that no person could reasonably
infer from representations made, or to be made, in connection with
the offering of Units that such sums as of such dates will exceed
two times the Partners' cash investments as of such dates.
12. The Managing General Partner believes that at least 90% of the gross
income of the Partnership will constitute income derived from the
exploration, development, production, and/or marketing of oil and
gas. The Managing General Partner does not believe that any market
will ever exist for the sale of Units and the Managing General
Partner will not make a market for the Units. Further, the Units
will not be traded on an established securities market or the
substantial equivalent thereof.
13. The Partnership and each Partner will have the objective of carrying
on business for profit and dividing the gain therefrom.
14. The Managing General Partner does not anticipate the purchase of
Units by tax-exempt investors or foreign investors.
Our opinions are also subject to all the assumptions, qualifications,
and limitations set forth in the following discussion, including the
assumptions that each of the Partners has full power, authority, and legal
right to enter into and perform the terms of the Partnership Agreement and
to take any and all actions thereunder in connection with the transactions
contemplated thereby.
Each prospective Investor should be aware that, unlike a ruling from
the Service, an opinion of counsel represents only such counsel's best
judgment. THERE CAN BE NO ASSURANCE THAT THE SERVICE WILL NOT
SUCCESSFULLY ASSERT POSITIONS WHICH ARE INCONSISTENT WITH OUR OPINIONS SET
FORTH IN THIS DISCUSSION OR IN THE TAX REPORTING POSITIONS TAKEN BY THE
PARTNERS OR THE PARTNERSHIP. EACH PROSPECTIVE INVESTOR SHOULD CONSULT HIS
OWN TAX ADVISOR TO DETERMINE THE EFFECT OF THE TAX ISSUES DISCUSSED HEREIN
ON HIS INDIVIDUAL TAX SITUATION.
PARTNERSHIP STATUS
The Partnership will be formed as a limited partnership pursuant to the
Partnership Agreement and the laws of the State of West Virginia. The<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-7
characterization of the Partnership as a partnership by state or local
law, however, will not be determinative of the status of the Partnership
for federal income tax purposes. The availability of any federal income
tax benefits to an investor is dependent upon classification of the
Partnership as a partnership rather than as a corporation or as an
association taxable as a corporation for federal income tax purposes.
NO TAX RULING WILL BE SOUGHT FROM THE SERVICE AS TO THE STATUS OF THE
PARTNERSHIP AS A PARTNERSHIP FOR FEDERAL INCOME TAX PURPOSES.
Although no tax ruling will be sought from the Service, we are of the
opinion that the Partnership will be treated as a partnership for federal
income tax purposes, and not as a corporation or as an association taxable
as a corporation. In the absence of a ruling from the Service, however,
there can be no assurance that the Service will not attempt to treat the
Partnership as a corporation or as an association taxable as a corporation
for federal income tax purposes. If the Service were to prevail on this
issue, the tax benefits associated with taxation as a partnership would
not be available to the Partners.
Although the Partnership will be validly organized as a limited
partnership under the laws of the state of West Virginia and will be
subject to the Act, whether it will be treated for federal income tax
purposes as a partnership or as a corporation or as an association taxable
as a corporation will be determined under the Code rather than local law.
Commissioner v. Tower, 327 U.S. 280 (1946); Treas. Reg. Section
301.7701-1(c). Thus, while local law will determine the legal
relationships between the Partners, the Partnership, and others, the
characterization of the Partnership for federal income tax purposes will
depend upon the application of the tests and standards set forth in the
Code and regulations. Id.
A. Association Taxable as a Corporation
Under Treasury regulations, a partnership will be subject to federal
income tax as a corporation or as an association taxable as a corporation
when its corporate characteristics exceed its non-corporate
characteristics. Treas. Reg. Section 301.7701-2(a)(1) provides that the
following characteristics are to be considered: (i) associates, (ii) an
objective to carry on business and divide the gains therefrom, (iii)
continuity of life, (iv) centralization of management, (v) limited
liability, and (vi) free transferability of interests. The Regulations
provide that, since associates and an objective to carry on business and
divide the profits therefrom are common to both corporations and
partnerships, an unincorporated organization is not classified as an
association unless it has at least three of the last four characteristics
noted above.<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-8
Where participants under an operating agreement have the right to take
in kind their shares of the minerals produced, the sale of the minerals,
even though made by the operator, is a sale by or on behalf of the
individual participants and not for their joint profit. Under rulings of
the Service, a joint profit motive is established only when the agreement
irrevocably vests the operator in his representative capacity with the
authority to extract and sell the minerals. I.T. 3930, 1948-2 C.B. 126.
Where the participants grant to the operator an option to purchase the
minerals produced, a question of representative capacity is not involved
and therefore a joint profit motive does not exist. I.T. 3948, 1949-1
C.B. 161.
The Service ruled on similar grounds in Rev. Rul. 68-344, 1968-1 C.B.
569, that where participants in an unincorporated organization formed to
operate a nuclear power plant had the right to and did take the
electricity produced in kind for separate disposition by each participant,
the organization lacked the objective to carry on business for joint
profit and was therefore taxable as a partnership and not as a
corporation. The Tax Court in Madison Gas & Electric Co. v. Commissioner,
72 T.C. 521 (1979), aff'd, 633 F.2d 512 (7th Cir. 1980), found on similar
facts that a partnership existed, although the question whether the
organization was an association was not raised.
Under the Partnership Agreement, the Partners will not reserve the
right to take in kind and separately dispose of their share of production.
Accordingly, the Partnership will not lack an objective to carry on
business for joint profit.
Continuity of Life. Section 301.7701-2(b)(1) of the Regulations
provides that an organization will be deemed to have continuity of life if
the death, insanity, bankruptcy, retirement, resignation, or expulsion of
any member will not cause a dissolution of the organization. On the other
hand, if the death, insanity, bankruptcy, retirement, resignation, or
expulsion of any member will cause a dissolution, continuity of life does
not exist. Section 301.7701-2(b)(3) of the Regulations further provides
that an organization lacks continuity of life if it is a limited
partnership subject to a statute corresponding to the Uniform Limited
Partnership Act (the "ULPA"). The Service, in Rev. Rul. 93-45, 1993-24
IRB 58, determined that the Act corresponds to the ULPA for purposes of
Treas. Reg. Section 301.7701-2.
Regulation Section 301.7701-2(b)(1) would prevent continuity of life
from existing in those cases where dissolution upon the withdrawal of a
general partner can be avoided by vote of a majority in interest (rather
than all) of the remaining partners.
Section 9.01(b) of the Partnership Agreement provides that:
The Partnership shall be dissolved upon the earliest to occur of:
(i) the written consent of the Investor Partners owning a
majority of the then-outstanding Units entitled to vote to
dissolve and wind<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-9
up the affairs of the Partnership; (ii) [unless a successor managing
general partner is selected by the Partners or the remaining
managing general partner (if any) continues the business of the
Partnership] the retirement, withdrawal, removal, death,
adjudication of insanity or incapacity, or bankruptcy (or, in the
case of a corporate managing general partner, the withdrawal,
removal, filing of a certificate of dissolution, liquidation, or
bankruptcy) of a managing general partner; (iii) the sale,
forfeiture, or abandonment of all or substantially all of the
Partnership's property; (iv) December 31, 2046; or (v) any event
causing dissolution of the Partnership under the Act.
Rev. Proc. 89-12, as amplified by Rev. Proc. 91-13, provides that the
Service will not rule that the corporate characteristic of continuity of
life is absent if, in the case of the removal of the general partner, the
partnership agreement permits holders of less than a majority of the
limited partnership interests to elect a new general partner to continue
the partnership. The Partnership Agreement, at Section 7.06(a), requires
the consent of Partners holding a majority of the then-outstanding Units
for the admission of a successor General Partner. Because it is unknown
what percentage of the Units will be held by Limited Partners, it is not
possible to determine whether the Partnership Agreement would satisfy the
criteria for lacking continuity of life as contained in Rev. Proc. 89-12,
as amplified by Rev. Proc. 91-13. However, since the Partnership will be
terminated upon the occurrence of those events specified above, under the
Regulations the Partnership will lack the corporate characteristic of
continuity of life so long as the Partnership remains subject to the Act
and the Act corresponds to the ULPA.
Centralization of Management. An organization has centralized
management if any person (or group of persons that does not include all
members) has continuing exclusive authority to make the management
decisions necessary to conduct the business for which the organization was
formed. Treas. Reg. Section 301.7701-2(c)(1). Treas. Reg.
Section 301.7701-2(c)(4) provides that a limited partnership subject to a
statute corresponding to the ULPA generally does not have the corporate
characteristic of centralized management, but adds that "centralized
management ordinarily does exist in such a limited partnership if
substantially all the interests in the partnership are owned by the
limited partners."
It is unclear how large the interests of the Managing General Partner
must be to avoid the corporate characteristic of centralized management.
Under the terms of the Partnership Agreement, 20% of Partnership profits
and a somewhat greater percentage of Partnership capital at the
commencement of the Partnership will be attributable to the Managing
General Partner, thereby potentially resulting in "substantially all" of
the Partnership's interests being treated as owned by Limited Partners.
Consequently, the Partnership may be deemed to possess the corporate
characteristic of centralized management, despite the fact that the
Partnership is subject to a statute corresponding to the ULPA.<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-10
Rev. Proc. 89-12, as amplified by Rev. Proc. 91-13, provides that the
Service will not rule that a partnership lacks centralized management if
limited partnership interests exceed 80% of the total interests in the
partnership. Because it is unknown whether more than 80% of the total
interests in the Partnership will be held by Limited Partners, it is
unknown whether the Partnership could satisfy the revenue procedure's
centralized management requirements.
Limited Liability. Treas. Reg. Section 301.7701-2(d)(1) provides that
an organization possesses the corporate characteristic of limited
liability if under local law there is no member who is personally liable
for the debts of or claims against the organization. Further, such
regulation provides that "[i]n the case of a limited partnership subject
to a statute corresponding to the Uniform Limited Partnership Act,
personal liability exists with respect to each general partner. . ." Id.
Notwithstanding that general rule, however, in the case of an
organization formed as a limited partnership, personal liability does not
exist with respect to a general partner when the general partner (i) has
no substantial assets (other than his interest in the partnership) which
could be reached by a creditor of the partnership, and (ii) is merely a
"dummy" acting as the agent of the limited partners. Treas. Reg.
Section 301.7701-2(d)(2). Further, the regulations provide that "[i]f the
limited partnership agreement provides that a general partner is not
personally liable to creditors for debts of the partnership . . . , it
shall be presumed that personal liability does not exist with respect to
that partner unless it is established that the provision is ineffective
under local law." Id.
While the Regulations do not define the term "dummy," the Tax Court and
the Court of Claims have focused on the meaning of the term. In Zuckman
v. United States, 524 F.2d 729 (Ct. Cl. 1975), the court in essence
defined a "dummy" as one who is an agent of the limited partners. The
sole corporate general partner in Zuckman was wholly-owned by an
individual limited partner. In rejecting the government's argument that
the corporation was a dummy, the court noted that if the corporation were
a dummy, the limited partner for whom it acted would be personally liable
for the debts of the partnership. Conversely, if not a dummy, the
corporate characteristic of limited liability would be lacking. The
court's analysis virtually assures any limited partnership of lacking the
corporate characteristic of limited liability.
In Phillip G. Larson v. Commissioner, 66 T.C. 159 (1976), acq. 1979-1
C.B. 1, the court applied a less restrictive analysis than that used by
the Court of Claims, defining a dummy as one controlled by the limited
partners. Unlike the corporate general partner in Zuckman, the Larson
general partner was not owned by the limited partners and the Tax Court
held the general partner was not a dummy.
In Rev. Proc. 89-12, as amplified by Rev. Proc. 91-13, the Service
stated that, for advance ruling purposes, a partnership will generally be<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-11
deemed to lack limited liability if the net worth of the corporate general
partners at the time of the ruling request equals at least 10 percent of
the total contributions to the limited partnership and is expected to
continue to equal that amount throughout the life of the partnership.
Although the Managing General Partner may not have the net worth
required to obtain a ruling from the Service, the Managing General Partner
has represented that it will have, at the time of admission of the
Investor Partners, a net worth in excess of $5,000,000 exclusive of its
interests in the Partnership and receivables from the Partnership.
Further, the Managing General Partner has represented that no agreement or
other arrangement exists or will exist between the Managing General
Partner and the Investor Partners which would be construed as creating a
"dummy" or an agency relationship within the meaning of the regulations.
Accordingly, the Partnership will, in our opinion, lack the corporate
characteristic of limited liability.
Free Transferability of Interests. An organization will be considered
to possess the corporate characteristic of free transferability of
interests if all of its members (or those members owning substantially all
of the organization's interests) have the power to transfer all attributes
of their interests in the entity, to others who are not members of the
entity, without the consent of other members. Treas. Reg.
Section 301.7701-2(e)(1). Further, if such a transfer results in the
dissolution of the old organization and the formation of a new
organization under local law, free transferability does not exist. Id.
In Rev. Proc. 92-33, 1992-1 G.B. 782, the Service announced that it
would generally rule privately that a partnership lacks free
transferability of interests if, throughout the life of the partnership,
the partnership agreement expressly restricts (within the meaning of
Regulation Section 301.7701-2(e)(1)) the transferability of partnership
interests representing more than 20 percent of all interests in
partnership capital, income, gain, loss, deduction, and credit. However,
the guideline does not represent substantive law and may not be followed
by the Service in all cases.
Section 7.03(a)(iii) of the Partnership Agreement requires the written
consent of the Managing General Partner, "the granting or denial of which
shall be within the absolute discretion of the Managing General Partner,"
to effectuate the transfer of an Investor Partner's interest in the
Partnership. Since the Investor Partners cannot transfer their interests
without the consent of the Managing General Partner, which can be withheld
in its absolute discretion, the corporate characteristic of free
transferability of interests will, in our opinion, be absent.
Other Factors. Section 301.7701-2 of the Treasury regulations provides
that, in addition to the major characteristics set forth above, other
factors may be found in some cases which may be significant in classifying
an organization as an association. Although the Service in Larson, supra,
argued that certain other factors should be considered in determining<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-12
whether a limited partnership should be classified as a partnership for
federal income tax purposes, the Tax Court rejected the Service's position
and held that such factors were either elements of the major factors
listed above or were not important in classifying the partnership for tax
purposes.
In Rev. Proc. 85-22, 1985-1 C.B. 550, the Service stated that an
advance ruling will not be issued unless the partnership agreement
provides that, upon the dissolution and termination of the partnership,
the general partners are obligated to contribute to the Partnership an
amount equal to the lesser of (i) the deficit balance in the capital
accounts or (ii) the excess of 1.01% of the total limited partner capital
contributions over the capital previously contributed by the general
partners. The Partnership Agreement provides, at section 3.01(e), that
the Managing
General Partner must restore any deficit balance in its Capital Account.
B. Publicly Traded Partnerships
The Revenue Act of 1987 (the "1987 Act") added Code Section 7704,
"Certain Publicly Traded Partnerships Treated as Corporations." In
treating certain "publicly traded partnerships" ("PTPs") as corporations
for federal income tax purposes, Congress defined a PTP as any
partnership, interests in which are either traded on an established
securities market or readily tradable on a secondary market (or the
substantial equivalent thereof). Code Section 7704(b). Proposed
Regulation 1.7704-1(b) provides that an "established securities market"
includes a national securities exchange registered under section 6 of the
Securities Exchange Act of 1934 (the "1934 Act"), a national securities
exchange exempt under the 1934 Act because of the limited volume of
transactions, certain foreign security laws, regional or local exchanges,
and an interdealer quotation system that regularly disseminates firm buy
or sell quotations by identified brokers or dealers. The Managing General
Partner has represented that the Units will not be traded on an
established securities market.
Notwithstanding the above general treatment of PTPs, Code
Section 7704(c) creates an exception to the treatment of PTPs as
corporations for any taxable year if 90% or more of the gross income of
the partnership for such taxable year consists of "qualifying income."
Code Section 7704(c)(2). For this purpose, qualifying income is defined
to include, inter alia, "income and gains derived from the exploration,
development, mining or production, processing, refining . . . or the
marketing of any mineral or natural resource . . ." Code
Section 7704(d)(1)(E). The Managing General Partner has represented that
it believes that, for all taxable years of the Partnership, 90% or more of
the Partnership's gross income will consist of such qualifying income.
Regarding the definition of PTPs contained in the Code, the Committee
Reports to the 1987 Act provide that PTPs include entities with respect to
which, inter alia, (i) "the holder of an interest has a readily available,
regular and ongoing opportunity to sell or exchange his interest through<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-13
a public means of obtaining or providing information of offers to buy,
sell or exchange interests," (ii) "prospective buyers and sellers have the
opportunity to buy, sell or exchange interests in a time frame and with
the regularity and continuity that the existence of a market maker would
provide," and (iii) there exists a "regular plan of redemptions or
repurchases, or similar acquisitions of interests in the partnership such
that holders of interests have readily available, regular and ongoing
opportunities to dispose of their interests."
The Service issued proposed Regulation Section 1.7704-1 to clarify when
partnership interests that are not traded on an established securities
market will be treated as readily tradable on a secondary market or the
substantial equivalent thereof. Essentially, the proposed Regulation
provides that such a situation occurs if partners are readily able to buy,
sell, or exchange their partnership interests in a manner that is
comparable, economically, to trading on an established securities market.
In addition, Notice 88-75 and the proposed Regulation provide limited safe
harbors from the definition of a PTP in advance of the issuance of final
regulations. It is unclear whether the limited safe harbors provided in
the Notice and proposed Regulation would result in the Units being treated
as not publicly traded and we express no opinion regarding this matter.
However, the Managing General Partner's obligation to offer to purchase
any Units is conditioned upon the receipt by the Partnership from its
counsel of an opinion that such offers or obligations to offer will not
cause the Partnership to be treated as "publicly traded."
Due to the presence of the opinion of counsel condition, the
Partnership, in our opinion, will not be treated as a PTP prior to the
time any such offers are made to Investor Partners. Accordingly, the
Partnership, in our opinion, will not be treated as a corporation for
federal income tax purposes under Code Section 7704 in the absence of the
Partnership's interests being "readily tradable on a secondary market (or
the substantial equivalent thereof)."
Notwithstanding the above, the Service may promulgate regulations or
release announcements which take the position that interests in
partnerships such as the Partnership are readily tradable on a secondary
market or the substantial equivalent thereof. However, treatment of the
Partnership as a PTP should not result in its treatment as a corporation
for federal income tax purposes due to the exception contained in Code
Section 7704(c) relating to PTPs meeting the 90% of gross income test so
long as such gross income test is satisfied.
C. Summary
Based on the above, the Partnership may be considered to possess the
corporate characteristic of centralized management but should be
considered as not possessing the corporate characteristics of continuity
of life, limited liability, and free transferability of interests.
Because the number of corporate characteristics listed in Treas. Reg.
Section 301.7701-2 that may be present should not exceed the number of<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-14
such characteristics that should be considered to be absent, in our
opinion the Partnership will be treated as a partnership and not as a
corporation or as an association taxable as a corporation for federal
income tax purposes. Further, since any right of the Managing General
Partner to offer to purchase Units is conditioned upon the receipt of an
opinion of counsel that the Partnership will not be treated as a PTP, and
assuming the Partnership satisfies the 90% gross income test of Code
Section 7704, the Partnership, in our opinion, will be treated as a
partnership and not as a corporation for federal income tax purposes. No
ruling, however, will be sought from the Service regarding the tax status
of the Partnership. If challenged by the Service on this issue, the
Partners should prevail on the merits, and each Partner should be required
to report his proportionate share of the Partnership's items of income and
deductions on his individual federal income tax return.
If in any taxable year the Partnership were to be treated for federal
income tax purposes as a corporation or as an association taxable as a
corporation, the Partnership income, gain, loss, deductions, and credits
would be reflected only on its "corporate" tax return rather than being
passed though to the Partners. In such event, the Partnership would be
required to pay income tax at corporate rates on its net income, thereby
reducing the amount of cash available to be distributed to the Partners.
Additionally, all or a portion of any distribution made to Partners would
be taxable as dividends, which would not be deductible by the Partnership
and which would generally be treated as ordinary portfolio income to the
Partners, regardless of the source from which such distributions were
generated.
The discussion that follows is based on the assumption that the
Partnership will be classified as a partnership for federal income tax
purposes.
FEDERAL TAXATION OF THE
PARTNERSHIP
Under the Code, a partnership is not a taxable entity and, accordingly,
incurs no federal income tax liability. Rather, a partnership is a "pass-
through" entity which is required to file an information return with the
Service. In general, the character of a partner's share of each item of
income, gain, loss, deduction, and credit is determined at the partnership
level. Each partner is allocated a distributive share of such items in
accordance with the partnership agreement and is required to take such
items into account in determining the partner's income. Each partner
includes such amounts in income for any taxable year of the partnership
ending within or with the taxable year of the partner, without regard to
whether the partner has received or will receive any cash distributions
from the Partnership.
A partnership anti-abuse regulation has recently been promulgated under
Reg. Section1.701-2 which authorizes the Service to recharacterize a
partnership transaction if (1) a partnership is formed or availed of in
connection with a transaction a principal purpose of which is to reduce<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-15
substantially the present value of the partners' aggregate federal income
tax liability, and (2) the transaction is inconsistent with the intent of
the Subchapter K partnership provisions. Additionally, the regulation
permits the Service to treat a partnership as an aggregate of its
partners, in whole or in part, as appropriate, to carry out the purpose of
any provision of the Code or the regulations. The scope of this
regulation is unclear at this time. Accordingly, Counsel is unable to
express an opinion as to its effect, if any, on the Partnership.
REGISTRATION AS A TAX SHELTER
The Code provides that certain investments must be registered as tax
shelters with the Service. Registration numbers for such tax shelters
must be supplied to investors who are required to report the numbers on
their personal tax returns. Any organizer of a "potentially abusive tax
shelter" and any person selling an interest in such shelter are required
to maintain a list of investors in such tax shelter to whom interests were
sold (together with other identifying information) and to make the list
available to the Service upon request. Any tax shelter which is required
to be registered and any other plan or arrangement which is of a type
determined by the Regulations as having a potential for tax avoidance or
evasion is considered a potentially abusive tax shelter for this purpose.
The registration requirements apply only to an investment with respect
to which any person could reasonably infer from the representations made,
or to be made, in connection with the offering for sale of interests in
the investment that the "tax shelter ratio" for any investor is greater
than two to one as of the close of any of the first five years ending
after the date on which such investment is offered for sale.
The Managing General Partner has represented that, (i) based upon its
experience with its previous drilling programs and upon the intended
operations of the Partnership, it does not believe that the Partnership
will have a tax shelter ratio greater than two to one, (ii) the deductions
and credits that are or will be represented as potentially allowable to an
investor will not result in any Partnership having a tax shelter ratio
greater than two to one, and (iii) based upon a review of the economics of
its similar oil and gas drilling programs for the past several years, it
has determined that none of those programs has resulted in a tax shelter
ratio greater than two to one. Accordingly, the Managing General Partner
does not intend to cause the Partnership to register with the Service as
a tax shelter. Based on the foregoing representations, we are of the
opinion that the Partnership will not be required to register with the
Service as a tax shelter.
If it is subsequently determined that the Partnership was required to
be registered with the Service as a tax shelter, the Partnership would be
subject to certain penalties under IRC Section 6707, including a penalty
ranging from $500 to 1% of the aggregate amount invested in Units for
failing to register and $100 for each failure to furnish to a Partner a
tax shelter registration number, and each Partner would be liable for a<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-16
$250 penalty for failure to include the tax registration number on his tax
return, unless such failure was due to reasonable cause. A Partner also
would be liable for a penalty of $100 for failing to furnish the tax
shelter registration number to any transferee of his Partnership interest.
Counsel can give no assurance that, if the Partnership is determined to be
a tax shelter which must be registered with the Service, the above
penalties will not apply.
INTANGIBLE DRILLING AND DEVELOPMENT COSTS
DEDUCTIONS
Under Code Section 263(a), taxpayers are denied deductions for capital
expenditures, which expenditures are those that generally result in the
creation of an asset having a useful life which extends substantially
beyond the close of the taxable year. See also Treas.
Reg.Section 1.461-1(a)(2). In Indopco, Inc. v. Commissioner, 92-1 USTC
paragraph 50,113 (1992) the Supreme Court seemed to further limit the
capitalization criteria by stating that the costs should be capitalized
when they provide benefits that extend beyond one tax year.
Notwithstanding these statutory and judicial general rules, Congress has
granted to the Treasury Secretary the authority to prescribe regulations
that would allow taxpayers the option of deducting, rather than
capitalizing, intangible drilling and development costs ("IDC"). Code
Section 263. The Secretary's rules are embodied in Treas. Reg.
Section 1.612-4 and state that, in general, the option to deduct IDC
applies only to expenditures for drilling and development items that do
not have a salvage value.
With respect to IDC incurred by a partnership, Code Section 703 and
Treas. Reg. Section 1.703-1(b) provide that the option to deduct such
costs is to be exercised at the partnership level and in the year in which
the deduction is to be taken. All partners are bound by the partnership's
election. The Managing General Partner has represented that the
Partnership will elect to deduct IDC in accordance with Treas. Reg.
Section 1.612-4. In this regard, Additional General Partners will be
entitled to deduct IDC against any form of income in the year in which the
investment is made, provided wells are spudded within the first ninety
days of the following year; subject to the same provision, Limited
Partners will be entitled to deduct IDC against passive income.
A. Classification of Costs
In general, IDC consists of those costs which in and of themselves have
no salvage value. Treas. Reg. Section 1.612-4(a) provides examples of
items to which the option to deduct IDC applies, including all amounts
paid for labor, fuel, repairs, hauling, and supplies, or any of them,
which are used (i) in the drilling, shooting, and cleaning of wells, (ii)
in such clearing of ground, draining, road making, surveying, and
geological works as are necessary in the preparation for the drilling of
wells, and (iii) in the construction of such derricks, tanks, pipelines,
and other physical structures as are necessary for the drilling of wells<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-17
and the preparation of wells for the production of oil or gas. The
Service, in Rev. Rul. 70-414, 1970-2 C.B. 132, set forth further
classifications of items subject to the option and those considered
capital in nature. The ruling provides that the following items are not
subject to the election of Treas. Reg. Section 1.612-4(a): (i) oil well
pumps (upon initial completion of the well), including the necessary
housing structures; (ii) oil well pumps (after the well has flowed for a
time), including the necessary housing structures; (iii) oil well
separators, including the necessary housing structures; (iv) pipelines
from the wellhead to oil storage tanks on the producing lease; (v) oil
storage tanks on the producing lease; (vi) salt water disposal equipment,
including any necessary pipelines; (vii) pipelines from the mouth of a gas
well to the first point of control, such as a common carrier pipeline,
natural gasoline plant, or carbon black plant; (viii) recycling equipment,
including any necessary pipelines; and (ix) pipelines from oil storage
tanks on the producing leasehold to a common carrier pipeline.
A partnership's classification of a cost as IDC is not binding on the
government, which might reclassify an item labelled as IDC as a cost which
must be capitalized. In Bernuth v. Commissioner, 57 T.C. 225 (1971),
aff'd, 470 F.2d 710 (2nd Cir. 1972), the Tax Court denied taxpayers a
deduction for that portion of a turnkey drilling contract price that was
in excess of a reasonable cost for drilling the wells in question under a
turnkey contract, holding that the amount specified in the turnkey
contract was not controlling. Similarly, the Service, in Rev. Rul. 73-
211, 1973-1 C.B. 303, concluded that excessive turnkey costs are not
deductible as IDC:
[O]nly that portion of the amount of the taxpayer's total investment
that is attributable to intangible drilling and development costs
that would have been incurred in an arm's-length transaction with an
unrelated drilling contractor (in accordance with the economic
realities of the transaction) is deductible [as IDC].
To the extent the Partnership's prices meet the reasonable price
standards imposed by Bernuth, supra, and Rev. Rul 73-211, supra, and to
the extent such amounts are not allocable to tangible property, leasehold
costs, and the like, the amounts paid to the Managing General Partner
under the drilling contract should qualify as IDC and should be deductible
at the time described below under "B. Timing of Deductions." That portion
of the amount paid to the Managing General Partner that is in excess of
the amount that would be charged by an independent driller under similar
conditions will not qualify as IDC and will be required to be capitalized.
We are unable to express an opinion regarding the reasonableness or
proper characterization of the payments under the drilling agreement,
since the determination of whether the amounts are reasonable or excessive
is inherently factual in nature. No assurance can be given that the
Service will not characterize a portion of the amount paid to the Managing
General Partner as an excessive payment, to be capitalized as a leasehold
cost, assignment fee, syndication fee, organization fee, or other cost,<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-18
and not deductible as IDC. To the extent not deductible, such amounts
will be included in the Partners' bases of their interests in the
Partnership.
B. Timing of Deductions
As described above, Code Section 263(c) and Treas. Reg. Section 1.612-4
allow the Partnership to expense IDC as opposed to capitalizing such
amounts. Even if the Partnership elects to expense the IDC, assuming a
taxpayer is otherwise entitled to such a deduction, the taxpayer may elect
to capitalize all or a part of the IDC and amortize same on a
straight-line basis over a sixty month period, beginning with the taxable
month in which such expenditure is made. Code Section 59(e)(1) and
(2)(c).
For taxpayers entitled to deduct IDC, the timing of such deduction can
vary, depending, in part, upon the taxpayer's method of accounting. The
Managing General Partner has represented that the Partnership will use the
accrual method of accounting. Under the accrual method, income is
recognized when all the events have occurred which fix the right to
receive such income and the amount thereof can be determined with
reasonable accuracy. Treas. Reg. Section 1.451-1(a). With respect to
deductions, recognition results when all events which establish liability
have occurred and the amount thereof can be determined with reasonable
accuracy. Treas. Reg. Section 1.461-1(a)(2). Regarding deductions, Code
Section 461(h)(1) provides that ". . . the all events test shall not be
treated as met any earlier than when economic performance with respect to
such item occurs."
Code Section 461(i)(2), provides that, in the case of a "tax shelter,"
economic performance with respect to the act of drilling an oil or gas
well will ". . . be treated as having occurred within a taxable year if
drilling of the well commences before the close of the 90th day after the
close of the taxable year." "Tax shelter," for purposes of Code
Section 461, is defined to include the Partnership. However, with respect
to a tax shelter which is a partnership, the maximum deduction that would
be allowable for any prepaid expenses under this exception would be
limited to the partner's "cash basis" in the partnership. Code
Section 461(i)(2)(B)(i). Such "cash basis" equals the partner's adjusted
basis in the partnership, determined without regard to (i) any liability
of the partnership and (ii) any amount borrowed by the partner with
respect to the partnership which (I) was arranged by the partnership or by
any person who participated in the organization, sale, or management of
the partnership (or any person related to such person within the meaning
of Code Section 465(b)(3)(C)) or (II) was secured by any assets of the
partnership. Code Section 461(i)(2)(C). The Managing General Partner has
represented that, as Operator, it will commence drilling operations by
spudding each well on or before March 30, 1995 for Partnerships designated
"PDC 1994-_ Limited Partnership" and March 30, 1996 for Partnerships
designated "PDC 1995-_ Limited Partnership" and will complete each well,
if completion is warranted, with due diligence thereafter. Further, the<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-19
Managing General Partner has represented that, in any event, the
Partnership will not have any such liability referred to in Code
Section 461(i)(2)(C), and the Partners will not so incur any such debt so
as to result in application of the limiting provisions contained in Code
Section 461(i)(2)(B)(i).
Notwithstanding the above, the deductibility of any prepaid IDC will be
subject to the limitations of case law. These limitations provide that
prepaid IDC is deductible when paid if (i) the expenditure constitutes a
payment that is not merely a deposit, (ii) the payment is made for a
business purpose, and (iii) deductions attributable to such outlay do not
result in a material distortion of income. See Keller v. Commissioner, 79
T.C. 7 (1982), aff'd, 725 F.2d 1173 (8th Cir. 1984), Rev. Rul. 71-252,
1971-1 C.B. 146, Pauley v. U.S., 63-1 U.S.T.C. paragraph 9280 (S.D. Cal.
1963), Rev. Rul. 80-71, 1980-1 C.B. 106, Jolley v. Commissioner, 47 T.C.M.
1082 (1984), Dillingham v. U.S., 81-2 U.S.T.C. paragraph 9601 (W.D. Okla.
1981), and Stradlings Building Materials, Inc. v. Commissioner, 76 T.C. 84
(1981). Generally, these requirements may be met by a showing of a
legally binding obligation (i.e., the payment was not merely a deposit),
of a legitimate
business purpose for the payment, that performance of the services was
required within a reasonable time, and of an arm's-length price. Similar
requirements apply to cash basis taxpayers seeking to deduct prepaid IDC.
The Managing General Partner is unable to represent that all of the
Wells will be completed in 1996 for Partnerships designated "PDC 1996-_
Limited Partnership" and 1997 for Partnerships designated "PDC 1997-_
Limited Partnership"; however, the Managing General Partner has
represented that any Well that is not completed in 1996 with respect to
Partnerships designated "PDC 1996-_ Limited Partnership" and in 1997 with
respect to Partnerships designated "PDC 1997-_ Limited Partnership" will
be spudded by not later than March 30, 1997 for Partnerships designated
"PDC 1996-_ Limited Partnership" and March 30, 1998 for Partnerships
designated "PDC 1997-_ Limited Partnership," respectively.
The Service has challenged the timing of the deduction of IDC when the
wells giving rise to such deduction have been completed in a year
subsequent to the year of prepayment. The decisions noted above hold that
prepayments of IDC by a cash basis taxpayer are, under certain
circumstances, deductible in the year of prepayment if some work is
performed in the year of prepayment even though the well is not completed
that year.
In Keller v. Commissioner, supra, the Eighth Circuit Court of Appeals
applied a three-part test for determining the current deductibility of
prepaid IDC by a cash basis taxpayer, namely whether (i) the expenditure
was a payment or a mere deposit, (ii) the payment was made for a valid
business purpose and (iii) the prepayment resulted in a material
distortion of income. The facts in that case dealt with two different
forms of drilling contracts: footage or day-work contracts and turnkey
contracts. Under the turnkey contracts, the prepayments were not
refundable in any event, but in the event work was stopped on one well the<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-20
remaining unused amount would be applied to another well to be drilled on
a turnkey basis. Contrary to the Service's argument that this
substitution feature rendered the payment a mere deposit, the court in
Keller concluded that the prepayments were indeed "payments" because the
taxpayer could not compel a refund. The court further found that the
deduction clearly reflected income because under the unique
characteristics of the turnkey contract the taxpayer locked in the price
and shifted the drilling risk to the contractor, for a premium,
effectively getting its bargained for benefit in the year of payment.
Therefore, the court concluded that the cash basis taxpayers in that case
properly could deduct turnkey payments in the year of payment. With
respect to the prepayments under the footage or day-work contracts,
however, the court found that the payments were mere deposits on the facts
of the case, because the partnership had the power to compel a refund.
The court was also unconvinced as to the business purpose for prepayment
under the footage or day-work contracts, primarily because the testimony
indicated that the drillers would have provided the required services with
or without prepayment.
Under the terms of the Drilling and Operating Agreement, if amounts
paid by the Partnership prior to the commencement of drilling exceed
amounts due the Managing General Partner thereunder, the Managing General
Partner will not refund any portion of amounts paid by the Partnership,
but rather will create a credit once the actual costs incurred by the
Managing General Partner are compared to the amounts paid. Further, the
Managing General Partner will expend such credit for additional IDC on
additional wells selected by the Managing General Partner.
The Service has adopted the position that the relationship between the
parties may provide evidence that the drilling contract between the
parties requiring prepayment may not be a bona fide arm's-length
transaction, in which case a portion of the prepayment may be disallowed
as being a "non-required payment." Section 4236, Internal Revenue Service
Examination Tax Shelters Handbook (6-27-85). A similar position is taken
by the Service in the Tax Shelter Audit Technique Guidelines. Internal
Revenue Service Examination Tax Shelter Handbook.
The Service has formally adopted its position on prepayments to related
parties in Revenue Ruling 80-71. 1980-1 C.B. 106. In this ruling, a
subsidiary corporation, which was a general partner in an oil and gas
limited partnership, prepaid the partnership's drilling and completion
costs under a turnkey contract entered into with the corporate parent of
the general partner. The agreement did not provide for any date for
commencing drilling operations and the contractor, which did not own any
drilling equipment, was to arrange for the drilling equipment for the
wells through subcontractors. Revenue Ruling 71-252, supra, was factually
distinguished on the grounds of the business purpose of the transaction,
immediate expenditure of prepaid receipts, and completion of the wells
within two and one-half months. Rev. Rul. 80-71 found that the prepayment
was not made in accordance with customary business practice and held on
the facts that the payment was deductible in the tax year that the related<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-21
general contractor paid the independent subcontractor.
However, in Tom B. Dillingham v. United States, 1981-2 USTC
paragraph 9601 (D.C. Okla. 1981), the court held that, on the facts before
it, a contract between related parties requiring a prepaid IDC did give
rise to a deduction in the year paid. In that case, Basin Petroleum Corp.
("Basin") was the general partner of several drilling partnerships and
also served as the partnership operator and general contractor. As
general contractor, Basin was to conduct the drilling of the wells at a
fixed price on a turnkey basis under an agreement that required payment
prior to the end of the year in question. The stated reason for the
prepayment was to provide Basin with working capital for the drilling of
the wells and to temporarily provide funds to Basin for other operations.
The agreement required drilling to commence within a reasonable period of
time, and all wells were completed within the following year. Some of the
wells were drilled by Basin with its own rigs and some were drilled by
subcontractors. The court stated:
The fact that the owner and contractor is the general partner
of the partnership-owner does not change this result where, as
here, the Plaintiffs have shown that prepayment was required
for a legitimate business purpose and the transaction was not
a sham to merely permit Plaintiff to control the timing of the
deduction. IRC, Sec. 707(a). Plaintiffs were entitled to
rely upon Revenue Ruling 71-252 by reason of Income Tax
Regulations 26 C.F.R. Section 601.601(d)(2)(v)(e) . . .
Notwithstanding the foregoing, no assurance can be given that the Service
will not challenge the current deduction of IDC because of the prepayment
being made to a related party. If the Service were successful with such
challenge, the Partners' deductions for IDC would be deferred to later
years.
The timing of the deductibility of prepaid IDC is inherently a factual
determination which is to a large extent predicated on future events. The
Managing General Partner has represented that the Drilling and Operating
Agreement to be entered into with PDC by the Partnership will be duly
executed by and delivered to PDC, the Partnership, and PDC as attorney-in-
fact for the Partners and will govern the drilling, and, if warranted, the
completion of each of the Wells. The Drilling and Operating Agreement
requires PDC to commence drilling operations by spudding each Well on or
before March 30, 1997 for Partnerships designated "PDC 1996-_ Limited
Partnership" and March 30, 1998 for Partnerships designated "PDC 1997-_
Limited Partnership," and to complete each Well, if completion is
warranted, with due diligence thereafter. Also, under the terms of the
Drilling and Operating Agreement, PDC, as general contractor, will not
refund any portion of amounts paid in the event actual costs are less than
the amounts paid but will apply any such amounts solely for payment of
additional drilling services to the Partners. Based upon this
representation and others included within the opinion and assuming that
the Drilling and Operating Agreement will be performed in accordance with<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-22
its terms, we are of the opinion that the payment for IDC under the
Drilling and Operating Agreement, if made in 1996 for Partnerships
designated "PDC 1996-_ Limited Partnership" and 1997 for Partnerships
designated "PDC 1997-_ Limited Partnerships," will be allowable as a
deduction in 1996 for Partnerships designated "PDC 1996-_ Limited
Partnership" and 1997 for Partnerships designated "PDC 1997-_ Limited
Partnerships," subject to the other limitations discussed in this opinion.
Although PDC will attempt to satisfy each requirement of the Service and
judicial authority for deductibility of IDC in 1996 for Partnerships
designated "PDC 1996-_ Limited Partnership" and 1997 for Partnerships
designated "PDC 1997-_ Limited Partnerships," no assurance can be given
that the Service will not successfully contend that the IDC of a well
which is not completed until 1997 for Partnerships designated "PDC 1996-_
Limited Partnership" and 1998 for Partnerships designated "PDC 1997-_
Limited Partnership" are not deductible in whole or in part until 1997 or
1998, respectively. Further, to the extent drilling of the Partnership's
wells does not commence by March 30, 1997 for Partnerships designated "PDC
1996-_ Limited Partnership" and March 30, 1998 for Partnerships designated
"PDC 1997-_ Limited Partnership," the deductibility of all or a portion of
the IDC may be deferred under Code Section 461.
C. Recapture of IDC
IDC which has been deducted is subject to recapture as ordinary income
upon certain dispositions (other than by abandonment, gift, death, or tax-
free exchange) of an interest in an oil or gas property. IDC previously
deducted that is allocable to the property (directly or through the
ownership of an interest in a partnership) and which would have been
included in the adjusted basis of the property is recaptured to the extent
of any gain realized upon the disposition of the property. Recently
promulgated Treasury regulations (effective with respect to any
disposition occurring after March 13, 1995) provide that recapture is
determined at the partner level (subject to certain anti-abuse
provisions). Treas. Reg. Section 1.1254-5(b). Where only a portion of
recapture property is disposed of, any IDC related to the entire property
is recaptured to the extent of the gain realized on the portion of the
property sold. In the case of the disposition of an undivided interest in
a property (as opposed to the disposition of a portion of the property) a
proportionate part of the IDC with respect to the property is treated as
allocable to the transferred undivided interest to the extent of any
realized gain. Treas. Reg. Section 1.1254-1(c).
DEPLETION DEDUCTIONS
The owner of an economic interest in an oil and gas property is
entitled to claim the greater of percentage depletion or cost depletion
with respect to oil and gas properties which qualify for such depletion
methods. In the case of partnerships, the depletion allowance must be
computed separately by each partner and not by the partnership. Code
Section 613A(c)(7)(D). Notwithstanding this requirement, however, the
Partnership, pursuant to Section 3.01(d)(i) of the Partnership Agreement,<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-23
will compute a "simulated depletion allowance" at the Partnership level,
solely for the purposes of maintaining Capital Accounts. Code Sections
613A(d)(2) and 613A(d)(4).
Cost depletion for any year is determined by multiplying the number of
units (e.g., barrels of oil or Mcf of gas) sold during the year by a
fraction, the numerator of which is the cost of the mineral interest and
the denominator of which is the estimated recoverable units of reserve
available as of the beginning of the depletion period. See Treas. Reg.
Section 1.611-2(a). In no event can the cost depletion exceed the
adjusted basis of the property to which it relates.
Percentage depletion is generally available only with respect to the
domestic oil and gas production of certain "independent producers." In
order to qualify as an independent producer, the taxpayer, either directly
or through certain related parties, may not be involved in the refining of
more 50,000 barrels of oil (or equivalent of gas) on any day during the
taxable year or in the retail marketing of oil and gas products exceeding
$5 million per year in the aggregate.
In general, (i) component members of a controlled group of
corporations, (ii) corporations, trusts, or estates under common control
by the same or related persons and (iii) members of the same family (an
individual, his spouse and minor children) are aggregated and treated as
one taxpayer in determining the quantity of production (barrels of oil or
cubic feet of gas per day) qualifying for percentage depletion under the
independent producer's exemption. Code Section 613A(c) (8). No
aggregation is required among partners or between a partner and a
partnership. An individual taxpayer is related to an entity engaged in
refining or retail marketing if he owns 5% or more of such entity. Code
Section 613A(d)(3).
Percentage depletion is a statutory allowance pursuant to which, under
current law, a minimum deduction equal to 15% of the taxpayer's gross
income from the property is allowed in any taxable year, not to exceed (i)
100% of the taxpayer's taxable income from the property (computed without
the allowance for depletion) or (ii) 65% of the taxpayer's taxable income
for the year (computed without regard to percentage depletion and net
operating loss and capital loss carrybacks). Code Sections 613(a) and
613A(d)(1). The rate of the percentage depletion deduction will vary with
the price of oil. In the case of production from marginal properties, the
percentage depletion rate may be increased. Section 613A(c)(6). For
purposes of computing the percentage depletion deduction, "gross income
from the property" does not include any lease bonus, advance royalty, or
other amount payable without regard to production from the property. Code
Section 613A(d)(5). Depletion deductions reduce the taxpayer's adjusted
basis in the property. However, unlike cost depletion, deductions under
percentage depletion are not limited to the adjusted basis of the
property; the percentage depletion amount continues to be allowable as a
deduction after the adjusted basis has been reduced to zero.
<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-24
Percentage depletion will be available, if at all, only to the extent
that a taxpayer's average daily production of domestic crude oil or
domestic natural gas does not exceed the taxpayer's depletable oil
quantity or depletable natural gas quantity, respectively. Generally, the
taxpayer's depletable oil quantity equals 1,000 barrels and depletable
natural gas quantity equals 6,000,000 cubic feet. Code Section 613A(c)(3)
and (4). In computing his individual limitation, a Partner will be
required to aggregate his share of the Partnership's oil and gas
production with his share of production from all other oil and gas
investments. Code Section 613A(c). Taxpayers who have both oil and gas
production may allocate the deduction limitation between the two types of
production.
The availability of depletion, whether cost or percentage, will be
determined separately by each Partner. Each Partner must separately keep
records of his share of the adjusted basis in an oil or gas property,
adjust such share of the adjusted basis for any depletion taken on such
property, and use such adjusted basis each year in the computation of his
cost depletion or in the computation of his gain or loss on the
disposition of such property. These requirements may place an
administrative burden on a Partner. For properties placed in service
after 1986, depletion deductions, to the extent they reduce the basis of
an oil and gas property, are subject to recapture under Section 1254.
SINCE THE AVAILABILITY OF PERCENTAGE DEPLETION FOR A PARTNER IS
DEPENDENT UPON THE STATUS OF THE PARTNER AS AN INDEPENDENT PRODUCER, WE
ALSO ARE UNABLE TO EXPRESS AN OPINION ON THIS MATTER. BECAUSE OF THE
FOREGOING, WE ARE UNABLE TO RENDER ANY OPINION AS TO THE AVAILABILITY OF
PERCENTAGE DEPLETION. EACH PROSPECTIVE INVESTOR IS URGED TO CONSULT WITH
HIS PERSONAL TAX ADVISOR TO DETERMINE WHETHER PERCENTAGE DEPLETION WOULD
BE AVAILABLE TO HIM.
DEPRECIATION DEDUCTIONS
The Partnership will claim depreciation, cost recovery, and
amortization deductions with respect to its basis in Partnership Property
as permitted by the Code. For most tangible personal property placed in
service after December 31, 1986, the "modified accelerated cost recovery
system" ("MACRS") must be used in calculating the cost recovery
deductions. Thus, the cost of lease equipment and well equipment, such as
casing, tubing, tanks, and pumping units, and the cost of oil or gas
pipelines cannot be deducted currently but must be capitalized and
recovered under "MACRS." The cost recovery deduction for most equipment
used in domestic oil and gas exploration and production and for most of
the tangible personal property used in natural gas gathering systems is
calculated using the 200% declining balance method switching to the
straight-line method, a seven-year recovery period, and a half-year
convention.
<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-25
INTEREST DEDUCTIONS
In the Transaction, the Investor Partners will acquire their interests
by remitting cash in the amount of $20,000 per Unit to the Partnership.
In no event will the Partnership accept notes in exchange for a
Partnership interest. Nevertheless, without any assistance of the
Managing General Partner or any of its affiliates, some Partners may
choose to borrow the funds necessary to acquire a Unit and may incur
interest expense in connection with those loans. Based upon the purely
factual nature of any such loans, we are unable to express an opinion with
respect to the deductibility of any interest paid or incurred thereon.
TRANSACTION FEES
The Partnership may classify a portion of the fees (the "Fees") to be
paid to third parties and to the Managing General Partner or to the
Operator and its affiliates (as described in the Prospectus under "Source
of Funds and Use of Proceeds") as expenses which are deductible as
organizational expenses or otherwise. There is no assurance that the
Service will allow the deductibility of such expenses and counsel
expresses no opinion with respect to the allocation of the Fees to
deductible and nondeductible items.
Generally, expenditures made in connection with the creation of, and
with sales of interests in, a partnership will fit within one of several
categories.
A partnership may elect to amortize and deduct its organizational
expenses (as defined in Code Section 709(b)(2) and in Treas. Reg.
Section 1.709-2(a)) ratably over a period of not less than 60 months
commencing with the month the partnership begins business. Organizational
expenses are expenses which (i) are incident to the creation of the
partnership, (ii) are chargeable to capital account, and (iii) are of a
character which, if expended incident to the creation of a partnership
having an ascertainable life, would (but for Code Section 709(a)) be
amortized over such life. Id. Examples of organizational expenses are
legal fees for services incident to the organization of the partnership,
such as negotiation and preparation of a partnership agreement, accounting
fees for services incident to the organization of the partnership, and
filing fees. Treas. Reg. Section 1.709-2(a).
Under Code Section 709, no deduction is allowable for "syndication
expenses," examples of which include brokerage fees, registration fees,
legal fees of the underwriter or placement agent and the issuer (general
partners or the partnership) for securities advice and for advice
pertaining to the adequacy of tax disclosures in the prospectus or private
placement memorandum for securities law purposes, printing costs, and
other selling or promotional material. These costs must be capitalized.
Treas. Reg. Section 1.709-2(b). Payments for services performed in
connection with the acquisition of capital assets must be amortized over
the useful life of such assets. Code Section 263.<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-26
Under Code Section 195, no deduction is allowable with respect to
"start-up expenditures," although such expenditures may be capitalized and
amortized over a period of not less than 60 months. Start-up expenditures
are defined as amounts (i) paid or incurred in connection with (I)
investigating the creation or acquisition of an active trade or business,
(II) creating an active trade or business, or (III) 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 such activity becoming
an active trade or business, and (ii) which, if paid or incurred in
connection with the operation of an existing active trade or business (in
the same field as the trade or business referred to in (i) above), would
be allowable as a deduction for the taxable year in which paid or
incurred. Code Section 195(c)(1).
The Partnership intends to make payments to the Managing General
Partner, as described in greater detail in the Prospectus. To be
deductible, compensation paid to a general partner must be for services
rendered by the partner other than in his capacity as a partner or for
compensation determined without regard to partnership income. Fees which
are not deductible because they fail to meet this test may be treated as
special allocations of income to the recipient partner (see Pratt v.
Commissioner, 550 F.2d 1023 (5th Cir. 1977)), and thereby decrease the net
loss or increase the net income among all partners.
To the extent these expenditures described in the Prospectus are
considered syndication costs (such as the fees paid to brokers and broker-
dealers, and the fees paid for printing the Prospectus and possibly all or
a portion of the Managing General Partner's management fee), they will be
nondeductible by the Partnership. To the extent attributable to
organization fees (such as the amounts paid for legal services incident to
the organization of the Partnership), the expenditures may be amortizable
over a period of not less than 60 months, commencing with the month the
Partnership begins business, if the Partnership so elects; if no election
is made, no deduction is available. Finally, to the extent any portion of
the expenditures would be treated as "start-up," they could be amortized
over a 60 month or longer period, provided the proper election was made.
Due to the inherently factual nature of the proper allocation of
expenses among nondeductible syndication expenses, amortizable
organization expenses, amortizable "start-up" expenditures, and currently
deductible items, and because the issues involve questions concerning both
the nature of the services performed and to be performed and the
reasonableness of amounts charged, we are unable to express an opinion
regarding such treatment. If the Service were to successfully challenge
the Managing General Partner's allocations, a Partner's taxable income
could be increased, thereby resulting in increased taxes and in liability
for interest and penalties.
<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-27
BASIS AND AT RISK LIMITATIONS
A Partner's share of Partnership losses will not be allowed as a
deduction to the extent such share exceeds the amount of the Partner's
adjusted tax basis in his Units. A Partner's initial adjusted tax basis
in his Units will generally be equal to the cash he has invested to
purchase his Units. Such adjusted tax basis will generally be increased
by (i) additional amounts invested in the Partnership, including his share
of net income, (ii) additional capital contributions, if any, and (iii)
his share of Partnership borrowings, if any, based on the extent of his
economic risk of loss for such borrowings. Such adjusted tax basis will
generally be reduced, but not below zero by (i) his share of loss, (ii)
his depletion deductions on his share of oil and gas income (until such
deductions exhaust his share of the basis of property subject to
depletion), (iii) distributions of cash and the adjusted basis of property
other than cash made to him, and (iv) his share of reduction in the amount
of indebtedness previously included in his basis.
In addition, Code Section 465 provides, in part, that, if an individual
or a closely held C (i.e., regularly taxed) corporation engages in any
activity to which Code Section 465 applies, any loss from that activity is
allowed only to the extent of the aggregate amount with respect to which
the taxpayer is "at risk" for such activity at the close of the taxable
year. Code Section 465(a)(1). A closely held C corporation is a
corporation, more than fifty percent (50%) of the stock of which is owned,
directly or indirectly, at any time during the last half of the taxable
year by or for not more than five (5) individuals. Code
Sections 465(a)(1)(B), 542(a)(2). For purposes of Code Section 465, a
loss is defined as the excess of otherwise allowable deductions
attributable to an activity over the income received or accrued from that
activity. Code Section 465(d). Any such loss disallowed by Code
Section 465 shall be treated as a deduction allocable to the activity in
the first succeeding taxable year. Code Section 465(a)(2).
Code Section 465(b)(1) provides that a taxpayer will be considered as
being "at risk" for an activity with respect to amounts including (i) the
amount of money and the adjusted basis of other property contributed by
the taxpayer to the activity, and (ii) amounts borrowed with respect to
such activity to the extent that the taxpayer (I) is personally liable for
the repayment of such amounts, or (II) has pledged property, other than
property used in the activity, as security for such borrowed amounts (to
the extent of the net fair market value of the taxpayer's interest in such
property). No property can be taken into account as security if such
property is directly or indirectly financed by indebtedness that is
secured by property used in the activity. Code Section 465(b)(2).
Further, amounts borrowed by the taxpayer shall not be taken into account
if such amounts are borrowed (i) from any person who has an interest
(other than an interest as a creditor) in such activity, or (ii) from a
related person to a person (other than the taxpayer) having such an
interest. Code Section 465(b)(3).
<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-28
Related persons for purposes of Code Section 465(b)(3) are defined to
include related persons within the meaning of Code Section 267(b) (which
describes relationships between family members, corporations and
shareholders, trusts and their grantors, beneficiaries and fiduciaries,
and similar relationships), Code Section 707(b)(1) (which describes
relationships between partnerships and their partners) and Code Section 52
(which describes relationships between persons engaged in businesses under
common control). Code Section 465(b)(3)(C).
Finally, no taxpayer is considered at risk with respect to amounts for
which the taxpayer is protected against loss through nonrecourse
financing, guarantees, stop loss agreements, or other similar
arrangements. Code Section 465(b)(4).
The Code provides that a taxpayer must recognize taxable income to the
extent that his "at risk" amount is reduced below zero. This recaptured
income is limited to the sum of the loss deductions previously allowed to
the taxpayer, less any amounts previously recaptured. A taxpayer may be
allowed a deduction for the recaptured amounts included in his taxable
income if and when he increases his amount "at risk" in a subsequent
taxable year.
The Treasury has published proposed regulations relating to the at risk
provisions of Code Section 465. These proposed regulations provide that
a taxpayer's at risk amount will include "personal funds" contributed by
the taxpayer to an activity. Prop. Treas. Reg. Section 1.465-22(a).
"Personal funds" and "personal assets" are defined in Prop. Treas. Reg.
Section 1.465-9(f) as funds and assets which (i) are owned by the
taxpayer, (ii) are not acquired through borrowing, and (iii) have a basis
equal to their fair market value.
In addition to a taxpayer's amount at risk being increased by the
amount of personal funds contributed to the activity, the excess of the
taxpayer's share of all items of income received or accrued from an
activity during a taxable year over the taxpayer's share of allowable
deductions from the activity for the year will also increase the amount at
risk. Prop. Treas. Reg. Section 1.465-22. A taxpayer's amount at risk
will be decreased by (i) the amount of money withdrawn from the activity
by or on behalf of the taxpayer, including distributions from a
partnership, and (ii) the amount of loss from the activity allowed as a
deduction under Code Section 465(a). Id.
The Partners will purchase Units by tendering cash to the Partnership.
To the extent the cash contributed constitutes the "personal funds" of the
Partners, the Partners should be considered at risk with respect to those
amounts. To the extent the cash contributed constitutes "personal funds,"
in our opinion, neither the at risk rules nor the adjusted basis rules
will limit the deductibility of losses generated from the Partnership.
<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-29
PASSIVE LOSS AND CREDIT LIMITATIONS
A. Introduction
Code Section 469 provides that the deductibility of losses generated
from passive activities will be limited for certain taxpayers. The
passive activity loss limitations apply to individuals, estates, trusts,
and personal service corporations as well as, to a lesser extent, closely
held C corporations. Code Section 469(a)(2).
The definition of a "passive activity" generally encompasses all rental
activities as well as all activities with respect to which the taxpayer
does not "materially participate." Code Section 469(c). Notwithstanding
this general rule, however, the term "passive activity" does not include
"any working interest in any oil or gas property which the taxpayer holds
directly or through an entity which does not limit the liability of the
taxpayer with respect to such interest." Code Section 469(c)(3),(4).
A passive activity loss ("PAL") is defined as the amount (if any) by
which the aggregate losses from all passive activities for the taxable
year exceed the aggregate income from all passive activities for such
year. Code Section 469(d)(1).
Classification of an activity as passive will result in the income and
expenses generated therefrom being treated as "passive" except to the
extent that any of the income is "portfolio" income and except as
otherwise provided in regulations. Code Section 469(e)(1)(A). Portfolio
income is income from, inter alia, interest, dividends, and royalties not
derived in the ordinary course of a trade or business. Income that is
neither passive nor portfolio is "net active income." Code
Section 469(e)(2)(B).
With respect to the deductibility of PALs, individuals and personal
service corporations will be entitled to deduct such amounts only to the
extent of their passive income whereas closely held C corporations (other
than personal service corporations) can offset PALs against both passive
and net active income, but not against portfolio income. Code
Section 469(a)(1), (e)(2). In calculating passive income and loss,
however, all activities of the taxpayer are aggregated. Code
Section 469(d)(1). PALs disallowed as a result of the above rules will be
suspended and can be carried forward indefinitely to offset future passive
(or passive and active, in the case of a closely held C corporation)
income. Code Section 469(b).
Upon the disposition of an entire interest in a passive activity in a
fully taxable transaction not involving a related party, any passive loss
that was suspended by the provisions of the Code Section 469 passive
activity rules is deductible from either passive or non-passive income.
The deduction must be reduced, however, by the amount of income or gain
realized from the activity in previous years.
<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-30
As noted above, a passive activity includes an activity with respect to
which the taxpayer does not "materially participate." A taxpayer will be
considered as materially participating in a venture only if the taxpayer
is involved in the operations of the activity on a "regular, continuous,
and substantial" basis. Code Section 469(h)(1). With respect to the
determination as to whether a taxpayer's participation in an activity is
material, temporary regulations issued by the Service provide that, except
for limited partners in a limited partnership, an individual will be
treated as materially participating in an activity if and only if (i) the
individual participates in the activity for more than 500 hours during
such year, (ii) the individual's participation in the activity for the
taxable year constitutes substantially all of the participation in such
activity of all individuals for such year, (iii) the individual
participates in the activity for more than 100 hours during the taxable
year, and such individual's participation in such activity is not less
than the participation in the activity of any other individual for such
year, (iv) the activity is a trade or business activity of the individual,
the individual participates in the activity for more than 100 hours during
such year, and the individual's aggregate participation in all significant
participation activities of this type during the year exceeds 500 hours,
(v) the individual materially participated in the activity for 5 of the
last 10 years, or (vi) the activity is a personal service activity and the
individual materially participated in the activity for any 3 preceding
years. Temp. Treas. Reg. Section 1.469-5T(a).
Notwithstanding the above, and except as may be provided in
regulations, Code Section 469(h)(2) provides that no limited partnership
interest will be treated as an interest with respect to which a taxpayer
materially participates. The temporary regulations create several
exceptions to this rule and provide that a limited partner will not be
treated as not materially participating in an activity of the partnership
of which he is a limited partner if the limited partner would be treated
as materially participating for the taxable year under paragraph (a)(1),
(5), or (6) of Treas. Reg. Section 1.469-5T (as described in (i), (v), and
(vi) of the above paragraph) if the individual were not a limited partner
for such taxable year. Temp. Treas. Reg. Section 1.469-5T(e). For
purposes of this rule, a partnership interest of an individual will not be
treated as a limited partnership interest for the taxable year if the
individual is an Additional General Partner in the partnership at all
times during the partnership's taxable year ending with or within the
individual's taxable year. Id.
B. General Partner Interests
Due to the factual nature of the applicability of the material
participation factors to an Additional General Partner's participation in
the activities of the Partnership, we cannot express an opinion with
respect to whether such participation will be material. However, the
"working interest" exception to the passive activity rules applies without
regard to the level of the taxpayer's participation. Nevertheless, the
presence or absence of material participation may be relevant for purposes<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-31
of determining whether the investment interest expense rules of Code
Section 163(d) apply to limit the deductibility of interest incurred in
connection with any borrowings of an Additional General Partner.
As noted above, the term "passive activity" does not include any
working interest in any oil or gas property which the taxpayer holds
directly or through an entity which does not limit the taxpayer's
liability with respect to such interest. Temp. Treas. Reg. Section 1.469-
1T(e)(4)(v) describes an interest in an entity that limits a taxpayer's
liability with respect to the drilling or operation of a well as (i) a
limited partnership interest in a partnership in which the taxpayer is not
a general partner, (ii) stock in a corporation, or (iii) an interest in
any other entity that, under applicable state law, limits the interest
holder's potential liability. For purposes of this provision,
indemnification agreements, stop loss arrangements, insurance, or any
similar arrangements or combinations thereof are not taken into account in
determining whether a taxpayer's liability is limited. Id.
The Joint Committee on Taxation's General Explanation of the Tax Reform
Act of 1986 (the "Bluebook") indicates that a "working interest" is an
interest with respect to an oil and gas property that is burdened with the
cost of development and operation of the property, and that generally has
characteristics such as responsibility for signing authorizations for
expenditures with respect to the activity, receiving periodic drilling and
completion reports and reports regarding the amount of oil extracted,
voting rights proportionate to the percentage of the working interest
possessed by the taxpayer, the right to continue activities if the present
operator decides to discontinue operations, a proportionate share of tort
liability with respect to the property and some responsibility to share in
further costs with respect to the property in the event a decision is made
to spend more than amounts already contributed. The Regulations define a
working interest as "a working or operating mineral interest in any tract
or parcel of land (within the meaning of Section 1.612-4(a))." Treas.
Reg. Section 1.469-1(e)(4)(iv). Under Treas. Reg. Section 1.614-2(b), an
operating mineral interest is defined as
a separate mineral interest as described in section 614(a), in
respect of which the costs of production are required to be taken
into account by the taxpayer for purposes of computing the
limitation of 50 percent of the taxable income from the property in
determining the deduction for percentage depletion computed under
section 613, or such costs would be so required to be taken into
account if the . . . well . . . were in the production stage. The
term does not include royalty interests or similar interests, such
as production payments or net profits interests. For the purpose of
determining whether a mineral interest is an operating mineral
interest, "costs of production" do not include intangible drilling
and development costs, exploration expenditures under section 615,
or development expenditures under section 616. Taxes, such as
production taxes, payable by holders of nonoperating interests are
not considered costs of production for this purpose. A taxpayer may
not aggregate<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-32
operating mineral interests and nonoperating mineral interests such as
royalty interests.
The Managing General Partner has represented that the Partnership will
acquire and hold only operating mineral interests, as defined in Code
Section 614(d) and the regulations thereunder, and that none of the
Partnership's revenues will be from non-working interests.
To the extent that the Additional General Partners (in their capacity
as general partners) have working interests in the activities of the
Partnership for purposes of Code Section 469, we are of the opinion that
an Additional General Partner's interest in the Partnership (as a general
partner) will not be considered a passive activity within the meaning of
Code Section 469 and losses generated while such general partner interest
is held will not be limited by the passive activity provisions.
Notwithstanding this general rule, however, for purposes of Code
Section 469, the economic performance rules of Code Section 461 are
applied in a different manner from that described above in "Intangible
Drilling and Development Costs Deductions." Economic performance under
the passive loss rules is defined in Temp. Treas. Reg. Section 1.469-
1T(e)(4)(ii)(C)(2)(ii) as economic performance within the meaning of Code
Section 461(h), without regard to Code Section 461(i)(2) (which contains
the spudding rule). Accordingly, if an Additional General Partner's
interest is converted to that of a limited partner after the end of the
year in which economic performance is deemed to occur (under Code
Section 461), but prior to the spudding date provided in Code
Section 461(i)(2), any post-conversion losses will be passive,
notwithstanding the availability of such losses (under Code Section 461)
in a year in which the taxpayer held the interest in an entity that did
not limit his liability.
Notwithstanding the above, there can be no assurance that the Service
will not contend that all general partner interests should be regarded as
interests in a passive activity from the Partnership's inception due to
the conversion feature contained in the Partnership Agreement. However,
due to the exposure to unlimited liability for Partnership obligations
incurred prior to such conversion, an attack by the Service with respect
to the foregoing should not be successful. In addition, the temporary
regulations, at Section 1.469-1T(e)(4)(iii), example (1), respect the
nature of a general partnership interest prior to its conversion into
limited partnership form:
A, a calendar year individual, acquires on January 1, 1987, a
general partnership interest in P, a calendar year partnership
that holds a working interest in an oil or gas property.
Pursuant to the partnership agreement, A is entitled to
convert the general partnership interest into a limited
partnership interest at any time. On December 1, 1987,
pursuant to a contract with D, an independent drilling
contractor, P commences drilling a single well pursuant to the
working interest. Under<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-33
the drilling contract, P pays D for the drilling only as the work is
performed. All drilling costs are deducted by P in the year in
which they are paid. At the end of 1987, A converts the general
partnership interest into a limited partnership interest, effective
immediately. The drilling of the well is completed on February 28,
1988.
Since, in the example, A holds the working interest through an entity that
does not limit A's liability throughout 1987 and through an entity that
does limit A's liability in 1988, the example in the regulation concludes
that A's interest in P's well is not an interest in a passive activity for
1987 but is an interest in a passive activity for 1988.
If an Additional General Partner converts his interest to a Limited
Partner interest pursuant to the terms of the Partnership Agreement, the
character of a subsequently generated tax attribute will be dependent
upon, inter alia, the nature of the tax attribute and whether there arose,
prior to conversion, losses to which the working interest exception
applied.
Assuming the activities of a converting partner will not result in the
Partner's being treated as materially participating under Temp. Treas.
Reg. Section 1.469-5T(a)(1), (5), or (6), as described above, the Limited
Partner's activity after conversion should be treated as a passive
activity. Code Section 469(c)(1). Accordingly, any loss arising
therefrom should be treated as a PAL under Code Section 469(d), with the
benefits thereof limited by Code Section 469(a)(1), as described above.
However, Code Section 469(c)(3)(B) provides that, if a taxpayer has any
loss from any taxable year from a working interest in any oil or gas
property that is treated as a non-passive loss, then any net income from
such property for any succeeding taxable year is to be treated as income
that is not from a passive activity. Consequently, assuming that a
converting Additional General Partner has losses from working interests
which are treated as non-passive, income from the Partnership allocable to
the Partner after conversion would be treated as income that is not from
a passive activity.
C. Limited Partner Interests
If an Investor Partner (other than an Additional General Partner who
converts his interest into that of a Limited Partner) invests in the
Partnership as a Limited Partner, in the opinion of counsel, his
distributive share of the Partnership's losses will be treated as PALs,
the availability of which will be limited to the Partner's passive income
thereon. If the Partner does not have sufficient passive income to
utilize the PAL, the disallowed PAL will be suspended and may be carried
forward (but not back) to be deducted against passive income arising in
future years. Further, upon the complete disposition of the interest to
an unrelated party, in a fully taxable transaction such suspended losses
will be available, as described above.<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-34
Regarding Partnership income, Limited Partners should generally be
entitled to offset their distributive shares of such income with
deductions from other passive activities, except to the extent such
Partnership income is portfolio income. Since gross income from interest,
dividends, annuities, and royalties not derived in the ordinary course of
a trade or business is not passive income, a Limited Partner's share of
income from royalties, income from the investment of the Partnership's
working capital, and other items of portfolio income will not be treated
as passive income. In addition, Code Section 469(l)(3) grants the
Secretary of the Treasury the authority to prescribe regulations requiring
net income or gain from a limited partnership or other passive activity to
be treated as not from a passive activity.
D. Publicly Traded Partnerships
Notwithstanding the above, Code Section 469(k) treats net income from
PTPs as portfolio income under the PAL rules. Further, each partner in a
PTP is required to treat any losses from a PTP as separate from income and
loss from any other PTP and also as separate from any income or loss from
passive activities. Id. Losses attributable to an interest in a PTP that
are not allowed under the passive activity rules are suspended and carried
forward, as described above. Further, upon a complete taxable disposition
of an interest in a PTP, any suspended losses are allowed (as described
above with respect to the passive loss rules). As noted above, we have
opined that the Partnership will not be a PTP.
In the event the Partnership were treated as a PTP, any net income
would be treated as portfolio income and each Partner's loss therefrom
would be treated as separate from income and loss from any other PTP and
also as separate from any income or loss from passive activities. Since
the Partnership should not be treated as a PTP, the provisions of Code
Section 469(k), in our opinion, will not apply to the Partners in the
manner outlined above prior to the time that such Partnership becomes a
PTP. However, unlike the PTP rules of Code Section 7704, the passive
activity rules of Code Section 469 do not provide an exception for
partnerships that pass the 90% test of Code Section 7704. Accordingly, if
the Partnership were to be treated as a PTP under the passive activity
rules, passive losses could be used only to offset passive income from the
Partnership.
CONVERSION OF INTERESTS
Code Section 708 provides that a partnership will be considered as
terminated for federal income tax purposes if, inter alia, there is "a
sale or exchange of 50 percent or more of the total interest in
partnership capital and profits" within a 12 month period. If a
conversion of an Additional General Partner's interest into a Limited
Partner interest were treated as a "sale or exchange" for purposes of Code
Section 708, the Partnership would be terminated for federal income tax
purposes if 50% or more of the profits and capital interests in the<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-35
Partnership were sold or exchanged within a 12 month period.
In Rev. Rul. 84-52, 1984-1 C.B. 157, the Service ruled that the
conversion of a general partnership interest into a limited partnership
interest in the same partnership will not give rise to the recognition of
gain or loss under Code Section 741 or Section 1001. The ruling noted
that, under Code Section 721, no gain or loss is recognized by a
partnership or any of its partners upon the contribution of property to
the partnership in exchange for an interest therein. Consequently, the
partnership will not be terminated under Code Section 708 since (i) the
business of the partnership will continue after the conversion and (ii)
pursuant to Treas. Reg. Section 1.708-1(b)(1)(ii) a transaction governed
by Code Section 721 is not treated as a sale or exchange for purposes of
Code Section 708. In the ruling, the Service also concluded that the
partners' bases in their partnership interests would be changed to the
extent of any change in their shares of the partnership's liabilities. To
the extent that a deemed distribution exceeds a partner's adjusted basis,
gain will be recognized to the extent of such excess.
If Rev. Rul. 84-52, supra, is not overruled, revoked, or modified, the
Partnership, in our opinion, will not be terminated under Code Section 708
solely as a result of the conversion of Partnership interests. In the
event a constructive termination does occur, however, there will be a
deemed distribution of the Partnership's assets to the Partners and a
recontribution by such Partners to the Partnership. This constructive
termination could have adverse federal income tax consequences, including
(i) the reallocation of basis of the assets, (ii) the recognition of
income by any Partner receiving a constructive distribution (including a
reduction in his share of Partnership liabilities) that exceeds his basis,
(iii) the loss of percentage depletion, if any, and (iv) the loss of
elections made by the Partnership.
Code Section 1245(a) provides that, inter alia, when Section 1245
property is disposed of, the amount by which the lower of (i) the
property's recomputed basis or (ii) the amount realized (on the sale,
exchange, or involuntary conversion) of the property or the fair market
value (on any other disposition) of the property exceeds the property's
adjusted basis is to be treated as ordinary income. Code
Section 1245(b)(3) provides that, if the basis of the property in the
hands of the transferee is determined by reference to its basis in the
hands of the transferor by reason of, inter alia, Code Section 721, then
the gain taken into account for purpose of Code Section 1245(a) is not to
exceed the gain taken into account by the transferor of such property
(without regard to Code Section 1245(b)). To the extent the conversion of
General Partner interests to Limited Partner interests is governed by Code
Section 721, the converting Partner will only be required to include in
ordinary income the amount of gain he otherwise would recognize with
respect to the "Section 1245" property attributable to him.
Code Section 752(b) treats any decrease in a partner's share of
partnership liabilities as a distribution of money to the partner by the<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-36
partnership. If, under the applicable regulatory or statutory provisions,
a converting partner's share of liabilities is deemed to decrease, such
decrease will result in gain to the partner to the extent it exceeds the
partner's basis in his partnership interest. Code Section 1254(a)
provides, in part, that when a property is disposed of, the taxpayer must
recapture as ordinary income any gain on disposition in an amount equal to
the aggregate of amounts deductible as IDC, in excess of the amount
deductible without regard to Code Section 263, and depletion. Code
Section 1254 (a) (1). Code Section 1254(b) provides that rules similar to
the rules of subsections (b) and (c) of Code Section 1245 are to be
applied for purposes of Code Section 1254. Consequently, to the extent
that a Partner could recognize ordinary income under Code Section 1245
upon conversion, the Partner could also recognize ordinary income under
Code Section 1254.
Losses arising from the holding of working interests in oil and gas
properties directly or through an entity that does not limit the holder's
liability are not subject to the passive loss rules. Temporary and
Proposed Regulations provide that, if the form of ownership is converted
from a type that does not limit liability to a type that does limit
liability, the portion of any losses (including those arising from the
deduction of IDC) attributable to services or materials which have not yet
been provided at the time of such conversion will constitute losses from
a passive activity. Thus, in our opinion, if a Partner were to convert
his general partner interest to that of a limited partner prior to the
time that all of the services or materials comprising the IDC of a well
had been provided, at the time of the conversion such services and
materials will constitute losses from a passive activity and be subject to
the passive loss limitations. Similarly in such a situation, a portion of
the income from the well would constitute passive income. If the
conversion were to occur after the filing of the Partnership's information
tax return but prior to the completion of the drilling and development of
a well, an amended return might have to be filed, which might also require
the Investors to file amended returns. Further, the Code provides that if
a taxpayer has any loss attributable to a working interest which is
treated in any taxable year as a loss which is not from a passive
activity, then any net income attributable to the working interest in any
succeeding taxable year is treated as income of the taxpayer which is not
from a passive activity. Accordingly, if an Additional General Partner
converts his interest into a Limited Partner interest, any income from
that interest with respect to which he claimed deductions will be treated
as nonpassive income.
ALTERNATIVE MINIMUM TAX
For taxable years beginning after December 31, 1992, Code 55 imposes on
noncorporate taxpayers a two-tiered, graduated rate schedule for
alternative minimum tax ("AMT") equal to the sum of (i) 26% of so much of
the "taxable excess" as does not exceed $175,000, plus (ii) 28% of so much
of the "taxable excess" as exceeds $175,000. Code Section 55(b)(1)(A)(i).<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-37
"Taxable excess" is defined as so much of the alternative minimum taxable
income ("AMTI") for the taxable year as exceeds the exemption amount.
Code Section 55(b)(1)(A)(ii). AMTI is generally defined as the taxpayer's
taxable income, increased or decreased by certain adjustments and items of
tax preference. Code Section 55(b)(2).
The exemption amount for noncorporate taxpayers is (i) $45,000 in the
case of a joint return or a surviving spouse, (ii) $33,750 in the case of
an individual who is not a married individual or a surviving spouse, and
(iii) $22,500 in the case of a married individual who files a separate
return or an estate or trust. Such amounts are phased out as a taxpayer's
AMTI increases above certain levels. Code Section 55(d)(1) and (3).
The corporate AMT is similar to that of the individual AMT, with the
corporation's regular taxable income increased or decreased by certain
adjustments and items of tax preference, resulting in AMTI. The AMTI is
reduced by $40,000 (which amount is phased-out as AMTI increases from
$150,000 to $310,000) with the balance being taxed at twenty percent
(20%). Code Section 55(b), (d). The excess of this figure over the
regular tax liability is the AMT.
Individuals subject to the AMT are generally allowed a credit, equal to
the portion of the AMT imposed by Code Section 55 arising as a result of
deferral preferences (or equal to the entire AMT in the case of corporate
AMT for use against the taxpayer's future regular tax liability (but not
the minimum tax liability). Code Section 53. However, for corporate
taxpayers after 1989, AMT arising from exclusion preferences is also
included in the credit. Code Section 53(d)(1)(B).
Under the AMT provisions, adjustments and items of tax preference that
may arise from a Partner's acquisition of an interest in the Partnership
include the following:
1. For taxable years beginning after December 31, 1992, taxpayers
which do not meet the definition of an integrated oil company as defined
in Code Section 291(b)(4) are not subject to the preference item for
"excess IDC." Code Section 57(a)(2)(E)(i). The benefit of the
elimination of the preference is limited in any taxable year to an amount
equal to 40 percent of the alternative minimum taxable income for the year
computed as if the prior law "excess IDC" preference item has not been
eliminated. Code Section 57(a)(2)(E)(ii). Excess IDC is defined as the
excess of (i) IDC paid or incurred (other than costs incurred in drilling
a nonproductive well) with respect to which a deduction is allowable under
Code Section 263(c) for the taxable year over (ii) the amount which would
have been allowable for the taxable year if such costs had been
capitalized and (I) amortized over a 120 month period beginning with the
month in which production from such well begins or (II) recovered through
cost depletion. Code Section 57(a)(2)(B). However, any portion of the
IDC to which an election under Code Section 59(e) applies will not be
treated as an item of tax preference under Code Section 57(a). Code
Section 59(e)(6). With respect to IDC paid or incurred, corporate and
individual taxpayers are<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-38
allowed to make the Code Section 59(e) election and, for regular tax and
AMT purposes, deduct such expenditures over the 60 month period beginning
with the month in which such expenditure is paid or incurred. Code
Section 59(e)(1).
2. For taxable years beginning after December 31, 1992, the preference
item for excess depletion is repealed for other than integrated oil
companies. Code Section 57(a)(1).
3. Each Partner's AMTI will be increased (or decreased) by the amount
by which the depreciation deductions allowable under Code Sections 167 and
168 with respect to such property exceeds (or is less than) the
depreciation determined under the alternative depreciation system using
the one hundred fifty percent (150%) declining balance method switching to
the straight-line method, when that produces a greater deduction, in lieu
of the straight-line method otherwise prescribed by the ADS. Code
Section 56(a)(1). No ACE depreciation adjustment is necessary with
respect to a corporate Partner for property placed in service in taxable
years beginning after December 31, 1993. Code Section 56(g)(4)(A)(i).
4. AMTI for a corporate Partner will be increased by seventy-five
percent (75%) of the excess of the taxpayer's "adjusted current earnings"
("ACE") over the AMTI amount (computed without the ACE adjustment and
without the net operating loss deduction). Code Section 56(g)(1). As
noted above, both corporate and individual taxpayers may elect this method
of amortization for regular tax purposes. For years beginning after
December 31, 1992, for corporations other than integrated oil companies,
the ACE adjustments for percentage depletion and IDC are repealed. Code
Sections 56(g)(4)(F) and (D)(i), respectively. The IDC modification
applies to IDCs paid or incurred in taxable years beginning after December
31, 1992.
Due to the inherently factual nature of the applicability of the AMT to
a Partner, we are unable to express an opinion with respect to such
issues. Due to the potentially significant impact of a purchase of Units
on an Investor's tax liability, investors should discuss the implications
of an investment in the Partnership on their regular and AMT liabilities
with their tax advisors prior to acquiring Units.
GAIN OR LOSS ON SALE OF PROPERTIES
Gain from the sale or other disposition of property is realized to the
extent of the excess of the amount realized therefrom over the property's
adjusted basis; conversely, loss is realized in an amount equal to the
excess of the property's adjusted basis over the amount realized from such
a disposition. Code Section 1001(a). The amount realized is defined as
the sum of any money received plus the fair market value of the property
(other than money) received. Code Section 1001(b). Accordingly, upon the
sale or other disposition of the Partnership properties, the Partners will
realize gain or loss to the extent of their pro rata share of the<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-39
difference between the Partnership's adjusted basis in the property at the
time of disposition and the amount realized upon disposition. In the
absence of nonrecognition provisions, any gain or loss realized will be
recognized for federal income tax purposes.
Gain or loss recognized upon the disposition of property used in a
trade or business and held for more than one year will be treated as long
term capital gain or as ordinary loss. Code Section 1231(a).
Notwithstanding the above, however, any gain realized may be taxed as
ordinary income under one of several "recapture" provisions of the Code or
under the characterization rules relating to "dealers" in personal
property.
Code Section 1254 generally provides for the recapture of capital
gains, arising from the sale of property which was placed in service after
1986, as ordinary income to the extent of the lesser of (i) the gain
realized upon sale of the property, or (ii) the sum of (I) all IDC
previously deducted and (II) all depletion deductions that reduced the
property's basis. Code Section 1254(a)(1).
Ordinary income may also result from the recapture, pursuant to Code
Section 1245, of depreciation on the Partnership properties. Such
recapture is the amount by which (i) the lower of (I) the recomputed basis
of the property, or (II) the amount realized on the sale of the property
exceeds (ii) the property's adjusted basis. Code Section 1245(a)(1).
Recomputed basis is generally the property's adjusted basis increased by
depreciation and amortization deductions previously claimed with respect
to the property. Code Section 1245(a)(2).
GAIN OR LOSS ON SALE OF UNITS
If the Units are capital assets in the hands of the Partners, gain or
loss realized by any such holders on the sale or other disposition of a
Unit will be characterized as capital gain or capital loss. Code
Section 1221. Such gain or loss will be a long term capital gain or loss
if the Unit is held for more than one year and a short term capital gain
or loss if held for a shorter period. However, the portion of the amount
realized by a Partner in exchange for a Unit that is attributable to the
Partner's share of the Partnership's "unrealized receivables" or
"substantially appreciated inventory items" will be treated as an amount
realized from the sale or exchange of property other than a capital asset.
Code Section 751.
Unrealized receivables are defined in Code Section 751(c) to include
". . . oil [or] gas . . . property . . . to the extent of the amount
which would be treated as gain to which section . . . 1245(a) . . . or
1254(a) would apply if . . . such property had been sold by the
partnership at its fair market value." A sale by the Partnership of the
Partnership's properties could give rise to treatment of the gain
thereunder as ordinary income as a result of Code Sections 1245(a) or
1254(a). Accordingly, gain recognized by a Partner on the sale of a Unit<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-40
would be taxed as ordinary income to the Partner to the extent of his
share of the Partnership's gain on property that would be recaptured, upon
sale, under those statutes.
Substantially appreciated inventory items are those "inventory items"
noted below, the fair market value of which exceeds 120% of the adjusted
basis to the partnership of such property, excluding any such inventory
property acquired with a principal purpose of avoiding Section751. Code
Section 751(d)(1). Property treated as an "inventory item" for purposes
of Code Section 751 includes (i) stock in trade of the partnership or
other property of a kind which would properly be included in its inventory
if on hand at the end of the taxable year, (ii) property held by the
partnership primarily for sale to customers in the ordinary course of its
trade or business, and (iii) any other partnership property which would
constitute neither a capital asset nor property used in a trade or
business under Code Section 1231. Code Sections 751(d)(2) and 1221(1).
Under the aforementioned provisions, a Partner would recognize ordinary
income with respect to any deemed sale of assets under Code Section 751;
further, this ordinary income may be recognized even if the total amount
realized on the sale of a Unit is equal to or less than the Partner's
basis in the Unit.
Any partner who sells or exchanges interests in a partnership holding
unrealized receivables (which include IDC recapture and other items) or
certain inventory items must notify the partnership of such transaction in
accordance with Regulations under Code Section 6050K and must attach a
statement to his tax return reflecting certain facts regarding the sale or
exchange. Regulations promulgated by the service provide that such notice
to the partnership must be given in writing within 30 days of the sale or
exchange (or, if earlier, by January 15 of the calendar year following the
calendar year in which the exchange occurred), and must include names,
addresses, and taxpayer identification numbers (if known) of the
transferor and transferee and the date of the exchange. Code Section 6721
provides that persons who fail to furnish this information to the
partnership will be penalized $50 for each such failure, or, if such
failure is due to intentional disregard to the filing requirement, the
person will be penalized the greater of (i) $100 or (ii) 10% of the
aggregate amount to be reported. Furthermore, a partnership is required
to notify the Service of any sale or exchange of interests of which it has
notice, and to report the names and addresses of the transferee and the
transferor, along with all other required information. The partnership
also is required to provide copies of the information it provides to the
Service to the transferor and the transferee.
The tax consequences to an assignee purchaser of a Unit from a Partner
are not described herein. Any assignor of a Unit should advise his
assignee to consult his own tax advisor regarding the tax consequences of
such assignment.
<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-41
PARTNERSHIP DISTRIBUTIONS
Under the Code, any increase in a partner's share of partnership
liabilities, or any increase in such partner's individual liabilities by
reason of an assumption by him of partnership liabilities is considered to
be a contribution of money by the partner to the partnership. Similarly,
any decrease in a partner's share of partnership liabilities or any
decrease in such partner's individual liabilities by reason of the
partnership's assumption of such individual liabilities will be considered
as a distribution of money to the partner by the partnership. Code
Section 752(a), (b).
The Partners' adjusted bases in their Units will initially consist of
the cash they contribute to the Partnership. Their bases will be
increased by their share of Partnership income and additional
contributions and decreased by their share of Partnership losses and
distributions. To the extent that such actual or constructive
distributions are in excess of a Partner's adjusted basis in his
Partnership interest (after adjustment for contributions and his share of
income and losses of the Partnership), that excess will generally be
treated as gain from the sale of a capital asset. In addition, gain could
be recognized to a distributee partner upon the disproportionate
distribution to a partner of unrealized receivables, substantially
appreciated inventory or, in some cases, Code Section 731 (c) marketable
securities, ie., actively traded financial instruments, foreign currencies
or interests in certain defined properties. Further, the Partnership
Agreement prohibits distributions to any Investor Partner to the extent
such would create or increase a deficit in the Partner's Capital Account.
PARTNERSHIP ALLOCATIONS
Allocations - General. Generally, a partner's taxable income is
increased or decreased by his ratable share of partnership income or loss.
Code Section 701. However, the availability of these losses may be
limited by the at risk rules of Code Section 465, the passive activity
rules of Code Section 469, and the adjusted basis provisions of Code
Section 704(d).
Code Section 704(b) provides that if a partnership agreement does not
provide for the allocation of each partner's distributive share of
partnership income, gain, loss, deduction, or credit, or if the allocation
of such items under the partnership agreement lacks "substantial economic
effect," then each partner's share of those items must be allocated "in
accordance with the partner's interest in the partnership."
As discussed below, regulations under Code Section 704(b) define
substantial economic effect and prescribe the manner in which partners'
capital accounts must be maintained in order for the allocations contained
in the partnership agreement to be respected. Notwithstanding these
provisions, special rules apply with respect to nonrecourse deductions<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-42
since, under the Regulations, allocations of losses or deductions
attributable to nonrecourse liabilities cannot have economic effect.
The Service may contend that the allocations contained in the
Partnership Agreement do not have substantial economic effect or are not
in accordance with the Partners' interests in the Partnership and may seek
to reallocate these items in a manner that will increase the income or
gain or decrease the deductions allocable to a Partner. We are of the
opinion that, to the extent provided herein, if challenged by the Service
on this matter, the Partners' distributive shares of partnership income,
gain, loss, deduction, or credit will be determined and allocated
substantially in accordance with the terms of the Partnership Agreement to
have substantial economic effect.
Substantial Economic Effect. Although a partner's share of partnership
income, gain, loss, deduction, and credit is generally determined in
accordance with the partnership agreement, this share will be determined
in accordance with the partner's interest in the partnership (determined
by taking into account all facts and circumstances) and not by the
partnership agreement if the partnership allocations do not have
"substantial economic effect" and if the allocations are not respected
under the nonrecourse deduction provisions of the regulations. Code
Section 704(b); Treas. Reg. Sections 1.704-1(b)(2)(i), 1.704-2.
Treasury regulations provide that:
In order for an allocation to have economic effect, it must be
consistent with the underlying economic arrangement of the partners.
This means that in the event there is an economic benefit or
economic burden that corresponds to an allocation, the partner to
whom the allocation is made must receive such economic benefit or
bear such economic burden.
Treas. Reg. Section 1.704-1(b)(2)(ii). The regulations further provide
that an allocation will have economic effect only if, throughout the full
term of the partnership, the partnership agreement provides (i) for the
determination and maintenance of partner's capital accounts in accordance
with specified rules contained therein, (ii) upon liquidation of the
partnership or a partner's interest in the partnership, liquidating
distributions are required to be made in accordance with the positive
capital account balances of the partners after taking into account all
capital account adjustments for the taxable year of the liquidation, and
(iii) either (I) a partner with a deficit balance in his capital account
following the liquidation is unconditionally obligated to restore the
amount of such deficit balance to the partnership by the end of the
taxable year of liquidation, or (II) the partnership agreement contains a
qualified income offset ("QIO") provision as provided in Treas. Reg.
Section 1.704-1(b)(2)(ii)(d). Treas. Reg. Sections 1.704-1(b)(2)(ii)(b)
and 1.704-1(b)(2)(ii)(d).
<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-43
The capital account maintenance rules generally mandate that each
partner's capital account be increased by (i) money contributed by the
partner to the partnership, (ii) the fair market value (net of
liabilities) of property contributed by the partner to the partnership,
and (iii) allocations to the partner of partnership income and gain.
Further, such capital account must be decreased by (i) money distributed
to the partner from the partnership, (ii) the fair market value (net of
liabilities) of property distributed to the partner from the partnership,
and (iii) allocations to the partner of partnership losses and deductions.
Treas. Reg. Section 1.704-1(b)(2)(iv).
Treas. Reg. Section 1.704-1(b)(2)(iii) provides that an economic effect
of an allocation is "substantial" if there is a reasonable possibility
that the allocation will affect substantially the dollar amounts to be
received by the partners from the partnership, independent of tax
consequences. The economic effect of an allocation is not substantial if:
at the time the allocation becomes part of the partnership
agreement, (1) the after-tax economic consequences of at least one
partner may, in present value terms, be enhanced compared to such
consequences if the allocation (or allocations) were not contained
in the partnership agreement, and (2) there is a strong likelihood
that the after-tax economic consequences of no partner will, in
present value terms, be substantially diminished compared to such
consequences if the allocation (or allocations) were not contained
in the partnership agreement. In determining the after-tax economic
benefit or detriment to a partner, tax consequences that result from
the interaction of the allocation with such partner's tax attributes
that are unrelated to the partnership will be taken into account.
Treas. Reg. 1.704-1(b)(2)(iii)(a).
While the Service stated that it will not rule on whether an allocation
provision in a partnership agreement has substantial economic effect,
several Technical Advice Memoranda ("TAMs") shed light on the Service's
position on such matter. Notwithstanding the potential similarity between
TAM and a taxpayer's particular fact pattern, it should be noted that TAMs
may not be used or cited as precedent. Code Section 6110(j)(3), Treas.
Reg. Sections 301.6110-2(a) and -7(b). Nevertheless, TAMs do serve to
illustrate the Service's position on certain specific cases. The TAMs
relating to substantial economic effect focus on the tax avoidance purpose
of any such above-described allocations and on the partnership plan for
distributions upon liquidation. Illustrative of the Service's approach is
TAM 8008054, in which the Service concluded that an allocation to the
partners solely of items that the partnership had elected to expense (IDC)
had as its principal purpose tax avoidance. The Service suggested that,
had the allocation affected the parties' liquidation rights, the
allocation would have had substantial economic effect: "In general,
substantial economic effect has been found where all allocations of items
of income, gain, loss, deduction or credit increase or decrease the
respective capital accounts of the partners and distribution of assets<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-44
made upon liquidation is made in accordance with capital accounts." The
ruling noted that the investors "should have been allocated their share of
costs over the intangible drilling costs." Id. The question whether
economic effect is "substantial" is one of fact which may depend in part
on the timing of income and deductions and on consideration of the
investors' tax attributes unrelated to their investment in Units, and thus
is not a question upon which a legal opinion can ordinarily be expressed.
However, to the extent the tax brackets of all Partners do not differ at
the time the allocation becomes part of the partnership agreement, the
economic effect of the allocation provisions should be considered to be
substantial.
Code Section 613A(c)(7)(D) requires that the basis of oil and gas
properties owned by a partnership be allocated to the partners in
accordance with their interests in the capital or income of the
partnership. Final Regulations issued under Code Section 613A(c)(7)(D)
indicate that such basis must be allocated in accordance with the
partners' interests in the capital of the partnership if their interests
in partnership income vary over the life of the partnership for any reason
other than for reasons such as the admission of a new partner. Reg.
Section 1.613A-3(e)(2). The terms "capital" and "income" are not defined
in the Code or in the Regulations under Section 613A. The Regulations
under Code Section 704 indicate that if all partnership allocations of
income, gain, loss, and deduction (or items thereof) have substantial
economic effect, an allocation of the adjusted basis of an oil or gas
property among the partners will be deemed to be made in accordance with
the partners' interests in partnership capital or income and will
accordingly be recognized.
Pursuant to the Partnership Agreement, (i) allocations will be made as
mandated by the Regulations, (ii) liquidating distributions will be made
in accordance with positive capital account balances, and (iii) a
"qualified income offset" provision applies. However, while capital will
be owned 78.125% by the Investor Partners and 21.875% by the Managing
General Partner, IDC will be allocated 100% to the Investor Partners and
other tax items will be allocated 80% to the Investor Partners. Except
with respect to those excess allocations, under the Partnership Agreement
the basis in oil and gas properties will be allocated in proportion to
each Partner's respective share of the costs which entered into the
Partnership's adjusted basis for each depletable property. Such
allocations of basis appear reasonable and in compliance with the
Regulations under Section 704. Nevertheless, the Service may contend that
the allocation to the Investors of IDC (100%) in excess of their capital
contributions (78.125%) or the allocation to the Managing General Partner
of other tax items (100% ranging to 0% upon the occurrence of certain
events) in excess of its capital contribution (21.875%) is invalid and may
reallocate such excess IDC or other items to the other Partners. Any such
reallocation could increase an Investor Partner's tax liability. However,
no assurance can be given, and we are unable to express an opinion, as to
whether any special allocation of an item which is dependent upon basis in
an oil and gas property will be recognized by the Service.<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-45
Allocation Shifts. Section 3.02(a) of the Partnership Agreement
provides that the Managing General Partner will subordinate up to 50% of
its 20% share of Partnership cash distributions so that the Investor
Partner might receive cash distributions equal to a minimum of 10% per
year of their Subscriptions on a cumulative basis for the first five years
of Partnership well operations. These shifts may trigger income to the
Partners to the extent such shift has the effect of reducing a Partner's
allocable share of "substantially appreciated inventory items" or
"unrealized receivables," as those terms are defined in Code Section 751.
Nonrecourse Deductions. As noted above, an allocation of loss or
deduction attributable to nonrecourse liabilities of a partnership cannot
have economic effect because the creditor alone bears any economic burden
that corresponds to such an allocation. Nevertheless, the Temporary
Regulations provide a test under which certain allocations of nonrecourse
deductions will be deemed to be in accordance with the partners' interests
in the partnership.
Nonrecourse deduction allocations will be deemed to be made in
accordance with partners' partnership interests if, and only if, four
requirements are satisfied. First, the partners' capital accounts must be
maintained properly and the distribution of liquidation proceeds must be
in accordance with the partners' capital account balances. Second,
beginning in the first taxable year in which there are nonrecourse
deductions, and thereafter throughout the full term of the partnership,
the partnership agreement must provide for allocation of nonrecourse
deductions among the partners in a manner that is reasonably consistent
with allocations, which have substantial economic effect, of some other
significant partnership item attributable to the property securing
nonrecourse liabilities of the partnership. Third, beginning in the first
taxable year of the partnership in which the partnership has nonrecourse
deductions or makes a distribution of proceeds of a nonrecourse liability
that are allocable to an increase in minimum gain, and thereafter
throughout the full term of the partnership, the partnership agreement
contains a "minimum gain chargeback." A partnership agreement contains a
"minimum gain chargeback" if, and only if, it provides that, subject to
certain exceptions, in the event there is a net decrease in partnership
minimum gain during a partnership taxable year, the partners must be
allocated items of partnership income and gain for that year equal to each
partner's share of the net decrease in partnership minimum gain during
such year. A partner's share of the net decrease in partnership minimum
gain is the amount of the total net decrease multiplied by the partner's
percentage share of the partnership's minimum gain at the end of the
immediately preceding taxable year. A partner's share of any decrease in
partnership minimum gain resulting from a revaluation of partnership
property (which would not cause a minimum gain chargeback) equals the
increase in the partner's capital account attributable to the revaluation
to the extent the reduction in minimum gain is caused by such revaluation.
Similar rules apply with regard to partner nonrecourse liabilities and
associated deductions. The fourth requirement of the nonrecourse
allocation test provides that all other material allocations and capital<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-46
account adjustments under the partnership agreement must be recognized
under the general allocation requirements of the regulations under IRC
Section 704(b).
Under the Regulations, partners generally share nonrecourse liabilities
in accordance with their interests in partnership profits. However, the
Regulations generally require that nonrecourse liabilities be allocated
among the partners first to reflect the partners' share of minimum gain
and Code Section 704(c) minimum gain. Any remaining nonrecourse
liabilities are generally to be allocated in proportion to the partner's
interests in partnership profits.
The Partnership Agreement, at Section 3.02, contains a minimum gain
chargeback. Further, the Partnership Agreement provides for the
allocation of nonrecourse liabilities and deductions attributable thereto
among the Partners first, in accordance with their respective shares of
partnership minimum gain (within the meaning of Regulation Section 1.704-
2(b)(2); second, to the extent of each such Partner's gain under Code
Section 704(c) if the Partnership were to dispose of (in a taxable
transaction) all Partnership property subject to one or more nonrecourse
liabilities of the Partnership in full satisfaction of such liabilities
and for no other consideration; and third, in accordance with the
Partners' proportionate shares in the Partnership's profits. Regulation
Section 1.752-3. For this purpose, the Partnership Agreement provides for
the allocation of excess nonrecourse deductions of 90% to the Investor
Partners and 10% to the Managing General Partner.
Retroactive Allocations. To prevent retroactive allocations of
partnership tax attributes to partners entering into a partnership late in
the tax year, Code Section 706(d) provides that a partner's distributive
share of such attributes is to be determined by the use of methods
prescribed by the Treasury Secretary which take into account the varying
interests of the partners during the taxable year.
The Partnership Agreement, at Section 3.04(c), provides that each
Partner's allocation of tax items other than "allocable cash basis items"
is to be determined under a method permitted by Code Section 706(d) and
the regulations thereunder. With respect to "allocable cash basis items,"
Section 3.04(c) requires an allocation in accordance with the requirements
of Code Section 706(d).
Accordingly, the Partnership allocations should be considered to be in
accordance with the provisions of Code Section 706(d).
PROFIT MOTIVE
The existence of economic, nontax motives for entering into the
Transaction is essential if the Partners are to obtain the tax benefits
associated with an investment in the Partnership.<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-47
Code Section 183(a) provides that where an activity entered into by an
individual is not engaged in for profit, no deduction attributable to that
activity will be allowed except as provided therein. Should it be
determined that a Partner's activities with respect to the Transaction
fall within the "not for profit" ambit of Code Section 183, the Service
could disallow all or a portion of the deductions and credits generated by
the Partnership's activities.
Code Section 183(d) generally provides for a presumption that an
activity is entered into for profit within the meaning of the statute
where gross income from the activity exceeds the deductions attributable
to such activity for three or more of the five consecutive taxable years
ending with the taxable year in question. At the taxpayer's election,
such presumption can relate to three or more of the taxable years in the
5-year period beginning with the taxable year in which the taxpayer first
engages in the activity. Temp. Treas. Reg. Section 12.9. Whether an
activity is engaged in for profit is determined under Code Sections 162
(relating to trade or business deductions) and 212(1) and (2) (relating to
income producing deductions) except insofar as the above-described
presumption applies. Treas. Reg. Section 1.183-1(a).
To establish that he is engaged in either a trade or business or an
income producing activity, a Partner must be able to prove that he is
engaged in the Transaction with an "actual and honest profit objective,"
Fox v. Commissioner, 80 T.C. 972, 1006 (1983), aff'd sub nom., Barnard v.
Commissioner, 731 F.2d 230 (4th Cir. 1984), and that his profit objective
is bona fide. Bessenyey v. Commissioner, 45 T.C. 261, 274 (1965), aff'd,
379 F.2d 252 (2d Cir. 1967), cert. denied, 389 U.S. 931 (1967). The
inquiry turns on whether the primary purpose and intention of the Partner
in engaging in the activity is, in fact, to make a profit apart from tax
considerations. Hager v. Commissioner, 76 T.C. 759, 784. Such objective
need not be reasonable, only honest, and the question of objective is to
be determined from all the facts and circumstances. Sutton v.
Commissioner, 84 T.C. 210 (1985), aff'd, 788 F.2d 695 (11th Cir. 1986).
Among the factors that will normally be considered are: (i) the manner in
which the taxpayer carries on the activity, (ii) the expertise of the
taxpayer or his advisors, (iii) the time and effort expended by the
taxpayer in carrying on the activity, (iv) whether an expectation exists
that the assets used in the activity may appreciate in value, (v) the
success of the taxpayer in carrying on similar or dissimilar activities,
(vi) the taxpayer's history of income or losses with respect to the
activity, (vii) the amount of occasional profits, if any, which are
earned, and (viii) the financial status of the taxpayer. Treas. Reg.
Section 1.183-2(b). Where application of such factors to a particular
activity is difficult, however, the Court will consider the totality of
the circumstances instead. Estate of Baron v. Commissioner, 83 T.C. 542
(1984), aff'd, 798 F.2d 65 (2d Cir. 1986).
As noted, the issue is one of fact to be resolved not on the basis of
any one factor but on the basis of all the facts and circumstances.
Treas. Reg. Section 1.183-2(b). Greater weight is given to objective
<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-48
facts than the parties' mere statements of their intent. Siegel v.
Commissioner, 78 T.C. 659, Engdahl v. Commissioner, 72 T.C. 659 (1979).
Nevertheless, the Courts have recognized, in applying Code Section 183,
that "a taxpayer has the right to engage in a venture which has economic
substance even though his motivation in the early years of the venture may
have been to obtain a deduction to offset taxable income." Lemmen v.
Commissioner, 77 T.C. 1326, 1346 (1981), acq., 1983-1 C.B. 1.
Due to the inherently factual nature of a Partner's intent and motive
in engaging in the Transaction, we do not express an opinion as to the
ultimate resolution of this issue in the event of a challenge by the
Service. Partners must, however, seek to make a profit from their
activities with respect to the Transaction beyond any tax benefits derived
from those activities or risk losing those tax benefits.
TAX AUDITS
Subchapter C of Chapter 63 of the Code provides that administrative
proceedings for the assessment and collection of tax deficiencies
attributable to a partnership must be conducted at the partnership, rather
than the partner, level. Partners will be required to treat Partnership
items of income, gain, loss, deduction, and credit in a manner consistent
with the treatment of each such item on the Partnership's returns unless
such Partner files a statement with the Service identifying the
inconsistency. If the Partnership is audited, the tax treatment of each
item will be determined at the Partnership level in a unified partnership
proceeding. Conforming adjustments to the Partners' own returns will then
occur unless such partner can establish a basis for inconsistent treatment
(subject to waiver by the Service).
PDC will be designated the "tax matters partner" ("TMP") for the
Partnership and will receive notice of the commencement of a Partnership
proceeding and notice of any administrative adjustments of Partnership
items. The TMP is entitled to invoke judicial review of administrative
determinations and to extend the period of limitations for assessment of
adjustments attributable to Partnership items. Each Partner will receive
notice of the administrative proceedings from the TMP and will have the
right to participate in the administrative proceeding pursuant to tax
requirements of Regulation Section 301.6223(g) unless the Partner waives
such rights.
The Code provides that, subject to waiver, partners will receive notice
of the administrative proceedings from the Service and will have the right
to participate in the administrative proceedings. However, the Code also
provides that if a partnership has 100 or more partners, the partners with
less than a 1% profits interest will not be entitled to receive notice
from the Service or participate in the proceedings unless they are members
of a "notice group" (a group of partners having in the aggregate a 5% or
more profits interest in the partnership that requires the Service to send
notice to the group and that designates one of their members to receive
notice). Any settlement agreement entered into between the Service and<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-49
one or more of the partners will be binding on such partners but will not
be binding on the other partners, except that settlement by the TMP may be
binding on certain partners, as described below. The Service must, on
request, offer consistent settlement terms to the partners who had not
entered into the earlier settlement agreement. If a partnership has more
than 100 partners, the TMP is empowered under the Code to enter into
binding settlement agreements on behalf of the partners with a less than
1% profits interest unless the partner is a member of a notice group or
notifies the Service that the TMP does not have the authority to bind the
partner in such a settlement.
BY EXECUTING THE PARTNERSHIP AGREEMENT EACH PARTNER RESPECTIVELY
REPRESENTS, WARRANTS, AND 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 SERVICE THAT THE TMP DOES NOT HAVE BINDING SETTLEMENT
AUTHORITY. Such waiver is permitted under the partnership audit
provisions of the Code and will be binding on the Partners.
The costs incurred by a Partner in responding to an administrative
proceeding will be borne solely by such Partner.
PENALTIES
Under IRC Section 6662, a taxpayer will be assessed a penalty equal to
twenty percent (20%) of the portion of an underpayment of tax attributable
to negligence, disregard of a rule or regulation or a substantial
understatement of tax. "Negligence" includes any failure to make a
reasonable attempt to comply with the tax laws. IRC Section 6662(c). The
regulations further provide that a position with respect to an item is
attributable to negligence if it lacks a reasonable basis. Treas. Reg.
Section 1.6662-3(b)(1). Negligence is strongly indicated where, for
example, a partner fails to comply with the requirements of IRC
Section 6662, which requires that a partner treat partnership items on its
return in a manner that is consistent with the treatment of such items on
the partnership return. Treas. Reg. Section 1.6662-3(b)(1)(iii). The
term "disregard" includes any careless, reckless or intentional disregard
of rules or regulations. Treas. Reg. Section 1.6662-3(b)(2). A taxpayer
who takes a position contrary to a revenue ruling or a notice will be
subject to a penalty for intentional disregard if the contrary position
fails to possess a realistic possibility of being sustained on its merits.
Treas. Reg. Section 1.6562-3(b)(2). An "understatement" is defined as the
excess of the amount of tax required to be shown on the return of the
taxable year over the amount of the tax imposed that is actually shown on
the return, reduced by any rebate. IRC Section 6662(d)(2)(A). An
understatement is "substantial" if it exceeds the greater of ten percent
(10%) of the tax required to be shown on the return for the taxable year
or $5,000 ($10,000 in the case of certain corporations). IRC
Section 6662(d)(1)(A) and (B).
<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-50
Generally, for tax returns with due dates (determined without regard to
extensions) after December 31, 1993, the amount of an understatement is
reduced by the portion thereof attributable to (i) the tax treatment of
any item by the taxpayer if there is or was substantial authority for such
treatment, or (ii) any item if the relevant facts affecting the item's tax
treatment are adequately disclosed in the return or in a statement
attached to the return, and there is a reasonable basis for the tax
treatment of such item by the taxpayer. IRC Section 6662(d). Disclosure
will generally be adequate if made on a properly completed Form 8275
(Disclosure Statement) or Form 8275R (Regulation Disclosure Statement)
Treas. Reg. Section 1.6662-4(f). However, in the case of "tax shelters,"
there will be a reduction of the understatement only to the extent it is
attributable to the treatment of an item by the taxpayer with respect to
which there is or was substantial authority for such treatment and only if
the taxpayer reasonably believed that the treatment of such item by the
taxpayer was more likely than not the proper treatment. Moreover, under
the GATT legislation, a corporation must generally satisfy a higher
standard to avoid a substantial understatement penalty in the case of a
tax shelter. IRC Section 6662(d)(2)(C)(ii). The term "tax shelter" is
defined for purposes of Code Section 6662 as a partnership or other
entity, any investment plan or arrangement, or any other plan or
arrangement, the principal purpose of which is the avoidance or evasion of
federal income tax. IRC Section 6662(d)(2)(C)(ii). It is important to
note that this definition of "tax shelter" differs from that contained in
Code Sections 461 and 6111, as discussed above. A tax shelter item
includes an item of income, gain, loss, deduction, or credit that is
directly or indirectly attributable to a partnership that is formed for
the principal purpose of avoiding or evading federal income tax. The
existence of substantial authority is determined as of the time the
taxpayer's return is filed or on the last day of the taxable year to which
the return relates and not when the investment is made. Treas. Reg.
Section 1.6662-4(d)(3)(iv)(C). Substantial authority exists if the weight
of authorities supporting a position is substantial compared with the
weight of authorities supporting contrary treatment. Treas. Reg.
Section 1.6662-4(d)(3)(i). Relevant authorities included statutes,
Regulations, court cases, revenue rulings and procedures, and
Congressional intent. However, among other things, conclusions reached in
legal opinions are not considered authority. Treas. Reg. Section 1.6662-
4(d)(3)(iii). The Secretary may waive all or a portion of the penalty
imposed under Code Section 6662 upon a showing by the taxpayer that there
was reasonable cause for the understatement and that the taxpayer acted in
good faith. IRC Section 6664(d).
Although not anticipated by PDC, there may not be substantial authority
for one or more reporting positions that the Partnership may take in its
federal income tax returns. In such event, if the Partnership does not
disclose or if it fails to adequately disclose any such position, or if
such disclosure is deemed adequate but it is determined that there was no
reasonable basis for the tax treatment of such a partnership item, the
penalty will be imposed with respect to any substantial understatement
determined to have been made, unless the provisions of the Regulations<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-51
pertaining to waiver of the penalty become final and the Partnership is
able to show reasonable cause and good faith in making the understatement
as specified in such provisions. If the Partnership makes a disclosure
for the purposes of avoiding the penalty, the disclosure is likely to
result in an audit of such return and a challenge by the Service of such
position taken.
If it were determined that a Partner had underpaid tax for any taxable
year, such Partner would have to pay the amount of underpayment plus
interest on the underpayment from the date the tax was originally due.
The interest rate on underpayments is determined by the Service based upon
the federal short term rate of interest (as defined in Code
Section 1274(d)) plus 3%, or 5% for large corporate underpayments, and is
compounded daily. The rate of interest is adjusted monthly. In addition,
Temporary Regulations provide that tax motivated transactions include,
among other items, certain overstatements of the value of property on a
return, losses disallowed by reason of the at-risk limitation, any use of
an accounting method that may result in a substantial distortion of income
for any period, and any deduction disallowed for an activity not entered
into for profit. Although definitive Regulations have not been
promulgated, the determination of those transactions to be considered
"tax-motivated transactions" is to be made by taking into account the
ratio of tax benefits to cash invested, the method of promoting the
transaction, and other relevant transactions. Thus, in the event an audit
of the Partnership's or of a Partner's tax return results in a substantial
underpayment of tax by such Partner due to an investment in the Units,
such Partner may be required to pay interest on such underpayment
determined at the higher interest rate.
A partnership, for federal income tax purposes, is required to file an
annual informational tax return. The failure to properly file such a
return in a timely fashion, or the failure to show on such return all
information under the Code to be shown on such return, unless such failure
is due to reasonable cause, subjects the partnership to civil penalties
under the Code in an amount equal to $50 per month multiplied by the
number of partners in the partnership, up to a maximum of $250 per partner
per year. In addition, upon any willful failure to file a partnership
information return, a fine or other criminal penalty may be imposed on the
party responsible for filing the return.
ACCOUNTING METHODS AND PERIODS
The Partnership will use the accrual method of accounting and will
select the calendar year as its taxable year.
As discussed above, a taxpayer using the accrual method of accounting
will recognize income when all events have occurred which fix the right to
receive such income and the amount thereof can be determined with
reasonable accuracy. Deductions will be recognized when all events which
establish liability have occurred and the amount thereof can be determined<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-52
with reasonable accuracy. However, all events which establish liability
are not treated as having occurred prior to the time that economic
performance occurs. Code Section 461(h).
All partnerships are required to conform their tax years to those of
their owners; i.e., unless the partnership establishes a business purpose
for a different tax year, the tax year of a partnership must be (i) the
taxable year of one or more of its partners who have an aggregate interest
in partnership profits and capital of greater than 50%, (ii) if there is
no taxable year so described, the taxable year of all partners having
interests of 5% or more in partnership profits or capital, or (iii) if
there is no taxable year described in (i) or (ii), the calendar year.
Code Section 706. Until the taxable years of the Partners can be
identified, no assurance can be given that the Service will permit the
Partnership to adopt a calendar year.
SOCIAL SECURITY BENEFITS;
SELF-EMPLOYMENT TAX
The Social Security Act and the Code exclude from the definition of
"net earnings from self-employment" a limited partner's (but not a general
partner's) distributive share of any item of income or loss from a
partnership other than a guaranteed payment for personal services actually
rendered. The determination of whether a particular activity is a trade
or business for the purposes of the self-employment tax is based on all of
the facts and circumstances surrounding the activity. Because of the
present uncertainty in the law, there can be no assurance that a General
Partner's share of income from the sale of production will not constitute
self-employment income. PDC, in the preparation of the information tax
returns for the Partnership, will make the determination of whether to
report income from the sale of production as income from self-employment
based upon guidance from tax advisors. Thus, a General Partner's share of
any income or loss attributable to his investment in Units may constitute
"net earnings from self-employment" for both social security and self-
employment tax purposes and, if any General Partners are receiving Social
Security benefits, their taxable income attributable to their investment
in the Units must be taken into account in determining any reduction in
benefits because of "excess earnings."
STATE AND LOCAL TAXES
The opinions expressed herein are limited to issues of federal income
tax law and do not address issues of state or local law. Investors are
urged to consult their tax advisors regarding the impact of state and
local laws on an investment in the Partnership.
PROPOSED LEGISLATION AND
REGULATIONS
<PAGE>
Petroleum Development Corporation
October 1, 1995
Page D-53
There can be no assurances that subsequent changes in the tax laws
(through new legislation, court decisions, Service pronouncements,
Treasury regulations, or otherwise) will or will not occur that may have
an impact, adverse or positive, on the tax effect and consequences of this
Transaction, as described above.
We express no opinion as to any federal income tax issue or other
matter except those set forth or confirmed above.
We hereby consent to the filing of this opinion as Appendix D to the
Prospectus and to all references to our firm in the Prospectus.
Sincerely,
/s/ METZGER, HOLLIS, GORDON & MORTIMER
