As filed with the Securities and Exchange Commission on January 29, 1998
Registration No. 333-41977
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
AMENDMENT NO. 2 TO FORM S-1
REGISTRATION STATEMENT
Under
THE SECURITIES ACT OF 1933
PDC 2000 DRILLING PROGRAM
(Exact name of registrant as specified in
its charter)
West Virginia 1381 Applied for
(State or other jurisdiction of (Primary Standard Industrial (IRS Employer
incorporation or organization) Classification Code Number) Identification #)
103 East Main Street
Bridgeport, West Virginia 26330
800/624-3821
(Address, including zip code, and telephone number, including area code,
of registrant's principal executive offices)
Steven R. Williams, President
Petroleum Development Corporation
103 East Main Street
Bridgeport, West Virginia 26330
800/624-3821
(Name, address including zip code, and telephone number, including
area code, of agent for service)
Copies to:
Laurence S. Lese
Duane, Morris, & Heckscher LLP
1667 K Street, N.W.
Washington, D.C. 20006
(202)776-7800
Approximate date of commencement of proposed sale to the public:
As soon as practicable after the registration statement becomes affective.
If any of the securities being registered on this Form are to be
offered on a delayed or continuous basis pursuant to Rule 415 the Securities
Act of 1933, check the following box.
X
<PAGE>
PROSPECTUS
PDC 2000 DRILLING PROGRAM
$1,500,000 Minimum Subscriptions Preformation General
Partnership Units and Limited Partnership Units $20,000 per Unit (Minimum
Subscription - $5,000
PDC 2000 Drilling Program (the "Program") is a series of up to
twelve limited partnerships which will be formed to drill, own, and
operate natural gas wells in West Virginia, Michigan, Pennsylvania, Ohio
New York, Kentucky, Indiana, Kansas, Montana, Wyoming, and/or Oklahoma.
Interests in the Program will be offered over a three-year period with
interests in the partnerships designated "PDC 1998-_ Limited Partnership"
being offered only during 1998 and interests in the partnerships
designated "PDC 1999-_ Limited Partnership" being offered only during 1999
and interests in the partnerships designated "PDC 2000-_ Limited
Partnership" being offered only during 2000. The primary purpose of the
partnerships will be to generate revenue from gas sales and distribute the
proceeds to the partners. See "Summary -- Terms of the Offering."
- The managing general partner anticipates that, if the minimum
offering of $1.5 million is achieved with respect to a
partnership, approximately 89.3% of the total capital
contributions of that partnership 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 and investment considerations 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<PAGE>
-- possible modification or elimination of tax benefits
-- 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.
Except as stated in the next sentence, the minimum capital for each
partnership to be raised from investors is $1.5 million, while the maximum
capital is $15 million. The minimum capital to be raised from investors
with respect to PDC 1998-D Limited Partnership, PDC 1999-D Limited
Partnership and PDC 2000-D Limited Partnership will be $2.5 million, while
the maximum capital for each of those Partnerships will be $25 million.
The managing general partner may terminate the offering of a particular
partnership at any point after the minimum subscription is reached at its
sole discretion, provided that no offering of the partnership designated
"PDC 1998-_ Limited Partnership" extend beyond December 31, 1998; no
offering of a partnership designated "PDC 1999-_ Limited Partnership" is
permitted to extend beyond December 31, 1999; and no offering of a
partnership designated "PDC 2000-_ Limited Partnership" is permitted to
extend beyond December 31, 2000. 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 at the
termination date for that 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. The offering period of
any Partnership during particular year will terminate on or before
December 31 of that year; the Managing General Partner is not permitted to
extend any offering period with respect to any Partnership beyond December
31 of any particular year. See "Terms of the Offering -- General."
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.
- 2 -
<PAGE>
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.
<TABLE>
<S> <S> <S> <S> <S> <S>
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.(2) $ 1,500,000 $ 157,500 (10.5%) $ 1,342,500 (89.5%)
Total Maximum. . .$150,000,000 $15,750,000 (10.5%) $134,250,000 (89.5%)
</TABLE>
(1) Before deducting expenses payable by the Partnership estimated at
$100,000 if the minimum number of Units is sold ranging to $500,000
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.
(2) With respect to each of PDC 1998-D Limited Partnership, PDC 1999-D
Limited Partnership, and PDC 2000-D Limited Partnership", the
minimum price to the public will be $2,500,000, the underwriting,
discounts and commissions will be $262,500 (10.5%), and the proceeds
to the Partnership will be $2,237,500 (89.5%).
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 , 1997.
- 3 -
<PAGE>
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.
- 4 -
<PAGE>
TABLE OF CONTENTS
Page
SUMMARY........................................................... 1
RISK FACTORS.......................................................10
Special Risks of the Partnership..............................11
Risks Pertaining to the Natural Gas Investment................16
Tax Status and Tax Risks......................................18
TERMS OF THE OFFERING..............................................20
General.......................................................20
Activation of Partnerships....................................24
Types of Units................................................25
Conversion of Units by Managing General Partner and
Additional General Partners..................................26
Unit Repurchase Program.......................................27
Investor Suitability..........................................28
ASSESSMENTS AND FINANCING..........................................31
SOURCE OF FUNDS AND USE OF PROCEEDS................................32
Source of Funds...............................................32
Use of Proceeds...............................................32
Subsequent Source of Funds....................................33
PARTICIPATION IN COSTS AND REVENUES................................33
Revenues......................................................34
Costs.........................................................35
Allocations Among Investor Partners; Deficit Capital Account
Balances.....................................................38
Cash Distributions Policy.....................................38
Termination...................................................39
Amendment of Partnership Allocation Provisions................40
COMPENSATION TO THE MANAGING GENERAL PARTNER AND AFFILIATES........40
PROPOSED ACTIVITIES................................................43
Introduction..................................................43
Drilling Policy...............................................45
Acquisition of Undeveloped Prospects..........................45
Title to Properties...........................................47
PDC Prospects.................................................48
Drilling and Completion Phase.................................54
Production Phase of Operations................................60
Interests of Parties..........................................61
Insurance.....................................................61
The Managing General Partner's Policy Regarding Roll-Up
Transactions.................................................63
COMPETITION, MARKETS AND REGULATION................................64
Competition and Markets.......................................64
Regulation....................................................66
i
<PAGE>
Page
Natural Gas Pricing...........................................67
Proposed Regulations..........................................67
MANAGEMENT.........................................................67
General Management............................................67
Experience and Capabilities as Driller/Operator...............68
Petroleum Development Corporation.............................68
Certain Shareholders of Petroleum Development Corporation.....70
Remuneration..................................................70
Legal Proceeding..............................................71
CONFLICTS OF INTEREST..............................................71
Certain Transactions..........................................75
FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER...........77
PRIOR ACTIVITIES...................................................78
Prior Partnerships............................................78
Previous Drilling Activities..................................81
Payout and Net Cash Tables....................................83
Tax Deductions and Tax Credits of Partnerships in Previous
Partnerships.................................................93
PARTNERSHIP PROVED RESERVES AND FUTURE NET REVENUES................98
TAX CONSIDERATIONS................................................100
Summary of Conclusions.......................................101
General Tax Effects of Partnership Structure.................104
Intangible Drilling and Development Costs Deductions.........105
A. Classification of Costs.............................106
B. Timing of Deductions................................106
C. Recapture of IDC....................................106
Depletion Deductions.........................................107
Depreciation Deductions......................................107
Interest Deductions..........................................108
Transaction Fees.............................................108
Basis and At Risk Limitations................................109
Passive Loss Limitations.....................................109
A. Introduction........................................109
B. General Partner Interests...........................110
C. Limited Partner Interests...........................111
Conversion of Interests......................................111
Alternative Minimum Tax......................................111
Gain or Loss on Sale of Property or Units....................127
Partnership Distributions....................................112
Partnership Allocations......................................113
Profit Motive................................................113
Administrative Matters.......................................114
Accounting Methods and Periods...............................115
ii<PAGE>
Page
Social Security Benefits; Self-employment tax...............115
State and Local Taxes.......................................115
Individual Tax Advice Should Be Sought......................115
SUMMARY OF PARTNERSHIP AGREEMENT..................................116
Responsibility of Managing General Partner..................116
Liabilities of General Partners, Including Additional
General Partners...........................................116
Liability of Limited Partners...............................116
Allocations and Distributions...............................117
Voting Rights...............................................117
Retirement and Removal of the Managing General Partner......118
Term and Dissolution........................................118
Indemnification.............................................118
Reports to Partners.........................................120
Power of Attorney...........................................120
Other Provisions............................................120
TRANSFERABILITY OF UNITS..........................................120
PLAN OF DISTRIBUTION..............................................122
SALES LITERATURE..................................................123
LEGAL OPINIONS....................................................123
EXPERTS...........................................................124
ADDITIONAL INFORMATION............................................124
GLOSSARY OF TERMS.................................................124
FINANCIAL STATEMENTS..............................................F-1
APPENDICES:
A. Form of Limited Partnership Agreement.........................A-1
B. Subscription Agreements.......................................B-1
C. Special Subscription Instructions.............................C-1
D. Opinion of Counsel -- Tax Considerations......................D-1
iii
<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 2000 Drilling Program (the "Program") is a series
of up to twelve 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 three-year period with
Units in the Partnerships designated "PDC 1998-_ Limited Partnership"
being offered only during 1998, Units in the Partnerships designated "PDC
1999-_ Limited Partnership" being offered only during 1999 and Units in
the Partnerships designated "PDC 2000-_ Limited Partnership" being offered
only during 2000. 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 1998-_
Limited Partnership", those designated "PDC 1999-_ Limited Partnership"and
designated "PDC 2000-_ Limited Partnership" will terminate on December 31,
1998, December 31, 1999, and December 31, 2000, respectively, unless
earlier terminated or withdrawn by the Managing General Partner.
A total of 7,500 Units at $20,000 per Unit, aggregating
$150,000,000, 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 75 Units, or $1,500,000 (125 Units or
$2,500,000 for each of PDC 1998-D Limited Partnership, PDC 1999-D Limited
Partnership and PDC 2000-D Limited Partnership. The maximum subscription
for any Partnership is $15,000,000 (750 Units) ($25,000,0000 or 1,250
units for PDC 1998-D Limited Partnership, PDC 1999-D Limited Partnership
and PDC 2000-D Limited Partnership). The Managing General Partner may
terminate the offering of a particular Partnership at any point after the
minimum subscription is reached at its sole discretion, provided that no
offering of any Partnership designated "PDC 1998-_ Limited Partnership,"
"PDC 1999-_ Limited Partnership," or "PDC 2000-_ Limited Partnership" is
permitted to extend beyond December 31, 1998, December 31, 1999 or
December 31, 2000, respectively. 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."
- 1 -<PAGE>
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, 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 1998-C Limited
Partnership or PDC 1998-D Limited Partnership or PDC 1999-C Limited
Partnership or PDC 1999-D Limited Partnership or PDC 2000-C Limited
Partnership or PDC 2000-D Limited Partnership has not closed on or before
December 31, 1998, December 31, 1999, or December 31, 2000, 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 $1,500,000 ($2,500,000 with respect to each of PDC 1998-D
Limited Partnership, PDC 1999-D Limited Partnership and PDC 2000-D Limited
Partnership) 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, Michigan, Pennsylvania and/or Ohio to
produce and sell gas from these wells. The Managing General Partner may
determine to drill wells in New York, Kentucky, Indiana, Kansas, Montana,
Wyoming and/or Oklahoma. 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 (304) 842-6256.
Conversion of Units by Managing General Partner and by Additional
General Partners. 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. Moreover, 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. See "Tax Considerations -- Conversion of Interests,"
"Terms of the Offering -- Conversion of Units by the Managing General
Partner and 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,
- 2 - <PAGE>
up to the 10% ceiling as stated above. The repurchase price will be based
upon a minimum of four 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."
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
- 3 - <PAGE>
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. There can be no assurance that any transaction
between Managing General Partner and affiliated parties will
be on terms or favorable as could have been negotiated with
unaffiliated third parties.
- The Managing General Partner and Affiliates will receive fees
and compensation throughout the life of each Partnership. The
Managing General Partner and its affiliate have interests
which inherently conflict with those of the unaffiliated
Partner. The Managing General Partner may have incentives to
act in a manner not in the best interests 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
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.
- 4 -
<PAGE>
Tax Risks:
- 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
exceed the cash distributed to such Partner by the
Partnership.
- Even though the Partnerships will not register with the
Internal Revenue Service (the "Service") as "tax shelters,"
there still remains a possibility of an audit of the
Partnerships' returns by the Service.
- Of the total Subscriptions, 10 1/2% is utilized for
syndication costs, offering costs, and commissions, and 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, gas marketing
Affiliates and other services(4)
- 5 -<PAGE>
Affiliate Brokerage sales commissions; 10.5% of Subscriptions
reimbursement of due $157,500 ranging to
diligence and marketing $15.75million(5)
support expenses; wholesaling
fees
<FN>
_____________________
(1) The Managing General Partner will contribute to the Partnerships an
amount in cash equal to at least 21-3/4% of the aggregate
contributions of the Investor Partners. The Managing General
Partner's share of Partnership distributions of 20% will be revised
under certain circumstances. See "Participation in Costs and
Revenues," below. If the Managing General Partner's required cash
Capital Contribution is insufficient to cover the cost of Leases and
tangible well equipment, and the Managing General Partner thereupon
makes an additional cash contribution to cover such costs, the
Managing General Partner's share of profits, losses, and cash
distributions will increase and the Investor Partners' share will
decrease. See "Participation in Costs and Revenues", below.
(2) The one-time fee will range from $37,500 if the minimum number of
Units is sold to $3,750,000 if the maximum number of Units is sold.
(3) Cannot be quantified until Partnership is conducting business.
(4) Some of the gas produced by the Partnerships may be marketed by
Riley Natural Gas Company ("Riley"), a subsidiary of the Managing
General Partner and a natural gas marketing company.
(5) 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 $15,750,000 if the maximum number of Units is
sold ranging to $157,500 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
$7,500 if the minimum number of Units is sold to $750,000 if the
maximum number of Units is sold.
</TABLE>
Participation in Costs and Revenue
Partnership profits and losses will generally be allotted 80% to the
Investor Partners and 20% to the Managing General Partner throughout the
term of each partnership; however, the Partnerships are structured to
enhance investor cash distributions during the first ten years of
Partnership well operations commencing six months after the close of a
Partnership for any Partnership which fails to meet the performance
standard described below. If the performance standard is not fulfilled by
a particular Partnership, that Partnership's sharing arrangement will be
modified for up to a ten-year period commencing six months after the
closing date of that Partnership and ending ten years later.
- 6 -
<PAGE>
The performance standard is as follows: If the Average Annual Rate
of Return, as defined below, to the Investor Partners is less than 12.8%
of their Subscriptions, the allocation rate of all items of profit and
loss and cash available for distribution for Investor Partners will be
increased by ten percentage points above the then-current sharing
arrangements for Investor Partners and the allocation rate with respect to
such items for the Managing General Partner will be decreased by ten
percentage points below then then-current sharing arrangements for the
Managing General Partner, until the Average Annual Rate of Return shall
have increased to 12.8% or more, or until ten years and six months shall
have expired from the closing date of the Partnership, whichever event
shall occur sooner. Average Annual Rate of Return for purposes of this
preferred sharing arrangement is defined as (1) the sum of cash
distributions, estimated initial tax savings of 28% of investor
subscriptions, and estimated tax savings from depletion based on a tax
rate of 28%, realized for a $10,000 investment in the Partnership, divided
by (2) $10,000 multiplied by the number of years (less six months) which
have elapsed since the closing of the Partnership. Thus Investor Partners
may receive up to 90% of Partnership distributions during the revision
period. See "Participation in Costs and Revenues -- Revenues -- Revisions
to Sharing Arrangements," below. THE ABOVE REFERENCED REVISED SHARING
ARRANGEMENT POLICY IS NOT, AND SHOULD NOT BE CONSIDERED BY AN INVESTOR
PARTNER TO BE, ANY FORM OF GUARANTEE OR ASSURANCE OF A RATE OF RETURN ON
AN INVESTMENT IN THE PARTNERSHIP. THE POLICY IS THE RESULT OF A
CONTRACTUAL AGREEMENT BY THE MANAGING GENERAL PARTNER AS SET FORTH IN
PARAGRAPH 4.02 OF THE PARTNERSHIP AGREEMENT. THERE IS NO GUARANTEE OR
ASSURANCE WHATSOEVER THAT THE PARTNERSHIP WILL DRILL COMMERCIALLY
SUCCESSFUL GAS WELLS OR THAT THE CASH DISTRIBUTIONS TO THE PARTNERS,
INCLUDING ANY CASH DISTRIBUTIONS PURSUANT TO THE POLICY, WILL ACHIEVE A
12.8% CUMULATIVE RATE OF RETURN.
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(2) General
Partners(3) Partner (2)(3)
Partnership Costs
Broker-dealer Commissions and Expenses(1). . . 100% 0%
Management Fee . . . . . . . . . . . . . . . . 100% 0%
Lease Costs. . . . . . . . . . . . . . . . . . 0% 100%
Total Tangible Equipment . . . . . . . . . . . 0% 100%
Intangible Drilling and Development Costs. . . 100% 0%
Drilling and Completion Costs. . . . . . . . . 80% 20%
Operating Costs. . . . . . . . . . . . . . . . 80% 20%
Direct Costs . . . . . . . . . . . . . . . . . 80% 20%
Administrative Costs . . . . . . . . . . . . . 0% 100%
Partnership Revenues
Sale of Oil and Gas Production . . . . . . . . 80% 20%
Sale of Productive Properties. . . . . . . . . 80% 20%
Sale of Equipment. . . . . . . . . . . . . . . 0% 100%
Sale of Undeveloped Leases . . . . . . . . . . 80% 20%
Interest Income. . . . . . . . . . . . . . . . 80% 20%
<FN>
____________________
- 7 -
<PAGE>
(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
- Revision to Sharing Agreements"), the allocations for Investor
Partners will be increased accordingly and the allocation for the
Managing General Partner will likewise be decreased.
(3) As set forth in the following paragraph, the allocation of profits,
losses, and cash distributions of the Managing General Partner might
be increased and the allocation of profits, losses, and cash
distributions, of the Investor Partners might be decreased in the
event that the Managing General Partner were to invest more than the
Managing General Partner's minimum required Capital Contribution to
cover tangible equipment and lease costs.
The Managing General Partner will pay for the Partnership's share of
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 and tangible well equipment were to
exceed the Managing General Partner's Capital Contribution of 21-3/4% 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 and the Managing General Partner's
allocation of profits, losses, and cash distributions will be increased to
equal the percentage arrived at by dividing the Capital Contribution made
by the Managing General Partner by the Capital Available for Investment,
and the allocation of the Investor Partners will be decreased accordingly.
</TABLE>
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>
-8-
<PAGE>
Tax Considerations; Opinion of Counsel
The Managing General Partner has received an opinion from its
counsel, Duane, Morris & Heckscher LLP, 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, Duane, Morris, & Heckscher LLP 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
drilled and amounts are timely paid, the Partners will be entitled to
their pro rata share of the Partnership's IDC paid in 1998 with respect to
Partnerships designated as "PDC 1998-_ Limited Partnership" and in 1999
with respect to Partnerships designated as "PDC 1999-_ Limited
Partnership"and in 2000 with respect to Partnerships designated as "PDC
2000-_ 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.
- 9 -
<PAGE>
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 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
of suitable only for investors of substantial financial means who have no
need of liquidity in their investments. This prospectus contains forward
looking statements including, without limitation, trends impacting the
natural gas industry (including prices and market demand), the
Partnership's success in drilling and development activities, the expected
effect of deregulation and the Partnerships' ability to expand its
drilling activities geographically, and anticipated tax consequences, that
involve risks and uncertainties. The Partnerships' actual results and
development could differ materially from those discussed or implied in the
forward-looking statements as a result of certain factors. Factors that
may cause or contribute to such differences include those discussed under
"Risk Factors,""Participation in Cost and Revenues,""Proposed
Activities,""Competition, Markets and Regulations," and Tax
Considerations," as well as those discussed elsewhere in this Prospectus.
The Managing General Partner cautions the reader, however, that this list
may not be exhaustive. Prospective investors should consider carefully
the following factors, in addition to the other information in this
Prospectus, prior to making their investment decision.
- 10 -<PAGE>
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 and Others for
Management of Partnerships and Partnership Properties; 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. Additionally, the
Partnership's might acquire a less than 50% Working Interest in various
Prospects. In such situations, the Managing General Partner may not be
able to manage and control Prospects; instead, parties other then the
Managing General Partner and the Investor Partners may control and manage
such properties. 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 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 in cash equal to not less than 21-3/4% 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 sharing arrangement policy and subject to
revision if the Managing General Partner makes contributions in excess of
the minimum required Capital Contributions to fund additional tangible
drilling and/or lease costs). The Partnership at closing of the
Partnership will pay to the Managing General Partner a one-time Management
- 11 -
<PAGE>
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. Payments will depend upon the location and depth of
wells drilled for a particular Partnership (see "Proposed Activities --
Drilling and Operating Agreement"). 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. There can be no assurance that
any transaction between the Managing General Partner and affiliated
partners will be on terms as favorable or could have been negotiated with
unaffiliated third parties. 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 $157,500 if the
minimum number of Units is sold to $15,750,000 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."
The Managing General Partner and its affiliates have interests which
inherently conflict with those of the unaffiliated Partners. 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 1998-C Limited
Partnership or PDC 1998-D Limited Partnership have not closed on or before
December 31, 1998 or the respective offerings of PDC 1999-C Limited
Partnership or PDC 1999- D Limited Partnership have not closed on or
before December 31, 1997 or the respective offerings of PDC 2000-C Limited
Partnership or PDC 2000-D Limited Partnership have not closed on or before
December 31, 2000, 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
- 12 -
<PAGE>
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 elect to
become Limited Partners could become subject to passive activity treatment
for Partnership deductions and thereby lose or suffer a deferral of the
benefits of some or all of such deductions. See "Tax Considerations --
Passive Loss and Credit Limitations." All Investor 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 seven 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. The Managing General
Partner and its affiliate have interests which inherently conflict with
those of the unaffiliated Partners. 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
- 13 -
<PAGE>
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). In addition, Riley Natural Gas, an
affiliate of the Managing General Partner and a natural gas marketing
company, may purchase some of the gas produced by the Partnership or
assist with marketing of Partnership gas for a fee. Such services will be
provided at competitive market rates. There can be no assurance that any
transaction between the Managing General Partner and affiliated partners
will be on terms as favorable as could have been negotiated with
unaffiliated third parties. In addition, the reasonableness of the fees
received in affiliated transactions has been assessed in the tax opinion
(See Appendix D).
No assurance can be given that the Service will not characterize a
portion of the amount paid to the Managing General Partner as unreasonable
and therefore an excessive payment, to be capitalized as a leasehold cost,
assignment fee, syndication fee, organization fee, or other cost, 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.
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. Additionally, the Partnership might purchase
less than a 50% Working Interest in one or more Prospects, a result of
which may be that someone other than the Partnership or the Managing
General Partner may control and manage such Prospects. 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."
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
1998 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
- 14 -
<PAGE>
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 minimum
requirement for any Partnership. The effect of this provision is that
substantially all 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
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
- 15 -
<PAGE>
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
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 varied
substantially over time and may in the future decline which would
adversely affect the Partnerships and the Investor Partners. Prices for
natural gas have been and are likely to remain extremely unstable.
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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. From time-to-time, a surplus of natural
gas may occurs in areas of the United States. The effect of a 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. The oil and gas industry historically
has experienced periods of 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. Increased drilling operations
in some areas of the United States have resulted 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 others to increase their domestic
oil and gas exploration. These features may reduce the availability of
rights to the Partnership resulting in delays in drilling activities.
White the Managing General Partner has not encountered significant
problems due to availability in recent years, when possible the Managing
General Partner arranges for drilling rigs in advance based on estimated
future levels of drilling activity. Such arrangements are generally non-
binding verbal agreements based on the Managing General Partner's best
estimates of anticipated drilling activities, and are typically arranged
no more than 6-9 months in advance of planned operations. The reduced
availability of rigs 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.
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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. 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. The Service could assert that a Partnership should
be classified 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 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.
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<PAGE>
Chance of Audits. Although the Partnerships will not be registered
with the Service as "tax shelters," it is possible 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, Duane, Morris & Heckscher LLP , has expressed no 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.
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."
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<PAGE>
Prepayment of Drilling Costs. Some drilling cost expenditures may
be made as prepayments during 1998 (with respect to Partnerships
designated as "PDC 1998-_ Limited Partnership"), 1999 (with respect to
Partnerships designated as "PDC 1999-_ Limited Partnership") and 2000
(with respect to Partnerships designated "PDC 2000-_ Limited
Partnership"), for drilling and completion operations which in large part
may be performed during 1999, 2000 and 2001, 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, 1998, 1999 or 2000,
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 twelve limited partnerships (four in 1998, four in 1999
and four in 2000)
- 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 -- $1,500,000 in subscriptions
- Maximum partnership -- $15,000,000 in subscriptions
- Maximum aggregate subscriptions for twelve partnerships --
$150,000,000
- Subscription proceeds will be placed in escrow until
Partnership funded.
An aggregate of $150,000,000 of preformation interests in a series
of up to twelve limited partnerships to be formed ("PDC 2000 Drilling
Program") is being offered in 7,500 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 three-year period with
interests in the partnerships designated "PDC 1998-_ Limited Partnership"
being offered only during 1998, interests in the partnerships designated
"PDC 1999-_ Limited Partnership" being offered only during 1999, and
interests in partnerships designated " PDC 2000-_ Limited Partnership"
being offered only during 2000. 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 (75 Units aggregating $1,500,000 ; 125 Units
aggregating $2,500,000 with respect to each of PDC 1998-D Limited
Partnership, PDC 1999-D Limited Partnership, and PDC 2000-D Limited
Partnership) and upon termination of the offering of Units in that
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<PAGE>
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.
If the minimum required aggregate subscription amount of $1,500,000
(or $2,500,000, as the case may be) 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 1998-A Limited
Partnership, PDC 1998-B Limited Partnership, PDC 1998-C Limited
Partnership, and PDC 1998-D Limited Partnership with respect to the
Partnerships to be offered during 1998, PDC 1999-A Limited Partnership,
PDC 1999-B Limited Partnership, PDC 1999-C Limited Partnership, and PDC
1999-D Limited Partnership with respect to the Partnerships to be offered
during 1999, and PDC 2000-A Limited Partnership, PDC 2000-B Limited
Partnership, PDC 2000-C Limited Partnership, and PDC 2000-D Limited
Partnership with respect to the Partnerships to be offered during 2000.
The maximum Subscription of any Partnership will be the lesser of
$15,000,000 ($25,000,000 with respect to each of PDC 1998-D Limited
Partnership, PDC 1999-D Limited Partnership, and PDC 2000-D Limited
Partnership) or the remaining unsold units based on the $150,000,000
aggregate registration.
The Subscription period for all Partnerships designated "PDC 1998-_
Limited Partnership" will terminate on December 31, 1998, whereas the
Subscription period for all Partnerships designated "PDC 1999-_ Limited
Partnership" will terminate on December 31, 1999, and whereas the
Subscription period for all Partnerships designated "PDC 2000-_ Limited
Partnership" will terminate on December 31, 2000, 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 1998-A Limited Partnership will
terminate on May 25, 1998, PDC 1998-B Limited Partnership on September 14,
1998, PDC 1998-C Limited Partnership on November 16, 1998, and PDC 1998-D
Limited Partnership will terminate on, December 31, 1998. The Managing
General Partner anticipates that the respective offering periods for PDC
1999-A Limited Partnership, PDC 1999-B Limited Partnership, PDC 1999-C
Limited Partnership, and PDC 1999-D Limited Partnership will terminate on
May 24, 1999, September 13, 1999, November 15, 1999, and December 31,
1999, and the Managing General Partner anticipates that the respective
offering periods for PDC 2000-A Limited Partnership, PDC 2000-B Limited
Partnership, PDC 2000-C Limited Partnership, and PDC 2000-D Limited
Partnership will terminate on May 22, 2000, September 18, 2000, November
13, 2000, and December 29, 2000. The offering of any particular
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<PAGE>
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 1998-_ Limited Partnership", Partnerships
designated "PDC 1999-_ Limited Partnership", or Partnerships designated
"PDC 2000-_ Limited Partnership" may extend beyond December 31, 1998,
December 31, 1999, or December 31, 2000, respectively. Except as otherwise
stated below, the offering of Units in subsequent Partnerships (PDC 1998-B
Limited Partnership, PDC 1998-C Limited Partnership or PDC 1998-D Limited
Partnership, PDC 1999-A Limited Partnership, PDC 1999-B Limited
Partnership, PDC 1999-C Limited Partnership, PDC 1999-D Limited
Partnership, or PDC 2000-A Limited Partnership, PDC 2000-B Limited
Partnership, PDC 2000-C Limited Partnership or PDC 2000-D Limited
Partnership as the case may be) will not commence until the Subscription
of Units in prior Partnerships (PDC 1998-A Limited Partnership, PDC 1998-B
Limited Partnership, PDC 1998-C Limited Partnership, PDC 1998-D Limited
Partnership, PDC 1999-A Limited Partnership, PDC 1999-B Limited
Partnership, PDC 1999-C Limited Partnership, or PDC 1999-D Limited
Partnership, PDC 2000-A Limited Partnership, PDC 2000-B Limited
Partnership, PDC 2000-C Limited Partnership or PDC 2000-D Limited
Partnership as the case may be) has reached the minimum of at least
$1,500,000 or that prior offering has terminated. The Managing General
Partner may choose to offer the Units of PDC 1998-C Limited Partnership
and PDC 1998-D Limited Partnership (or PDC 1999-C Limited Partnership and
PDC 1999-D Limited Partnership or PDC 2000-C Limited Partnership and PDC
2000-D Limited Partnership) at the same time until the offering of Units
in PDC 1998-C Limited Partnership (or PDC 1999-C Limited Partnership or
PDC 2000-C Limited Partnership) has been terminated, in order that
investors be allowed to diversify their investments in the two
Partnerships, if they 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 $1,500,000 (75 Units) ($2,500,000 or
125 Units with respect to each of PDC 1998-D Limited Partnership, PDC
1999-D Limited Partnership, and PDC 2000-D Limited Partnership). 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, 1998 or December
31, 1999, or December 31, 2000, with respect to Partnerships designated
"PDC 1998-_ Limited Partnership", "PDC 1999-_ Limited Partnership", or
"PDC 2000-_ 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 in cash equal to not less than 21-3/4% of the aggregate
contributions by the Investor Partners. The Managing General Partner is
obligated to pay for all Leases and tangible drilling Costs of the
Partnership 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.
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<PAGE>
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 $1,500,000 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 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 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 25, 1998 for PDC
1998-A Limited Partnership and September 14, 1998 for PDC 1998-B Limited
Partnership; May 24, 1999 for PDC 1999-A Limited Partnership, September
13, 1999 for PDC 1999-B Limited Partnership, and May 22, 2000 for PDC
2000-A Limited Partnership and September 18, 2000 for PDC 2000-B Limited
Partnership) will be promptly returned to the respective investor of that
Partnership. If the respective offering of Units in PDC 1998-C Limited
Partnership or PDC 1998-D Limited Partnership has not closed on or before
December 31, 1998 or if the respective offering of Units in PDC 1999-C
Limited Partnership or PDC 1999-D Limited Partnership has not closed on or
before December 31, 1999, of if the respective offering of Units in PDC
2000-C Limited Partnership or PDC 2000-D Limited Partnership has not
closed on or before December 31, 2000, 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 4.00%.
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. Checks for Units should be made payable to "PNC Bank,
N.A. as Escrow Agent for PDC 1998-_ Limited Partnership" (or "PNC Bank,
N.A. as Escrow Agent for PDC 1999-_ Limited Partnership," or "PNC Bank,
N.A. as Escrow Agent for PDC 2000-_ 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.
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<PAGE>
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 $1,500,000 ($2,500,000 with respect to PDC 1998-D Limited
Partnership, PDC 1999-D Limited Partnership, and PDC 2000-D Limited
Partnership). The Partnerships will not have any substantial assets or
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.
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.
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<PAGE>
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
activities will generally be allocable to the Partners who bear the
economic risk of loss with respect to such activities . 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.
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 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).
- 25 -
<PAGE>
General Partners. The General Partners will consist of the Managing
General Partner and each investor purchasing 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 the Managing General Partner and by Additional
General Partners
- The Managing General Partner will convert all Units of general
partnership interest into Units of limited partnership
interest upon completion of drilling.
- Additional General Partners may convert to become Limited
Partners after one year.
- 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.
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. In
addition, 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 one
year following the closing of the offering of that Partnership and the
disbursement to that Partnership of the proceeds of the offering.
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.
Upon conversion they will become Limited Partners of that Partnership.
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.
- 26 -
<PAGE>
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.
- Investors may, at their election, sell their Units to the
Managing General Partner for not less than four times the most
recent twelve months' cash distributions from production.
- The Managing General Partner is obligated to purchase in any
calendar year such Units which aggregate 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 the available borrowing capacity under its loan
agreemeents 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
Section 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. It is possible that
repurchases of Units could result in such Units being "Readily Tradable On
a Secondary Market or the substantial equivalent thereof", Code Section
7704(b)(2), the result of which the Partnership could be deemed to be a
"publicly traded partnership". To limit the possible of such
characterization, the Managing General Partner will require receipt of its
counsel's opinion as cited immediately above.
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, because of limitations imposed by
the Code or due to insufficient borrowing capacity under 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
- 27 -
<PAGE>
as a "publicly traded partnership." To the extent that the Managing
General Partner is unable to repurchase all Units tendered at the same
time by Partners of any Partnership, repurchases of these partnership
Units will be made on a pro rata basis.
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 four times cash distributions from
production of that particular Partnership for the twelve 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 86 units (out of approximately 3,477 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. The 3,477
units includes all partnerships through and including PDC 1993-E Limited
Partnership. More recent programs had not satisfied the three year
holding period. The figures reflect all partnerships formed by the
Managing General Partner from 1984 through 1993.
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.
- 28 -
<PAGE>
- 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
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, Pennsylvania and South Dakota investors are not permitted
to make an investment if the dollar amount of the investment is equal to
or more than 10% of their net worth.
Alaska investors are not permitted to make an investment unless
they meet either of the following requirements: the Alaska purchaser must
be (a) a person whose total purchase does not exceed 5% of his/her net
worth if the purchase of securities is at least $10,000, or (b) a person
with income in excess of $70,000 in the past two years as well as the
current year provided the amount of securities purchased does not exceed
10% of the current year's expected income.
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 1998
(with respect to investments in the PDC 1999 designated Partnerships) or
in 1999 (with respect to the PDC 1999 designated Partnerships), or in 2000
(with respect to the PDC 2000 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 1998 (with respect to
investments in the PDC 1998 designated Partnerships) or in 1999 (with
respect to the PDC 1999 designated Partnerships); or in 2000 (with respect
to the PDC 2000 designated Partnerships) of not less than $200,000.
- 29 -
<PAGE>
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, North Carolina, or South Dakota 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 1998 (with respect to
investments in the PDC 1998 designated Partnerships) or in 1999 (with
respect to the PDC 1999 designated Partnerships), or in 2000 (with respect
to the PDC 2000 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 1997 (for the PDC 1998 designated Partnerships; 1998 for
the PDC 1999 designated Partnerships), and 1999 for the PDC 2000
designated Partnerships) taxable income of or estimates that his 1998 (for
the PDC 1998 designated Partnerships; PDC 1999 for the PDC 1999 designated
Partnerships; 2000 for the PDC 2000 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.
Purchasers of General Partnership Interest. Except as otherwise
provided below, a resident of Alabama, Arizona, Arkansas, Indiana, Iowa,
Kansas, Kentucky, Maine, Massachusetts, Michigan, Minnesota, Mississippi,
Missouri, New Mexico, North Carolina, Ohio, Oklahoma, Oregon,
Pennsylvania, Tennessee, Texas, or Vermont 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 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; an investor in Arizona, Indiana, Iowa, Kansas,
Kentucky, Michigan, Missouri, Ohio, Oklahoma, Oregon, and Vermont must
represent that he has an individual or joint minimum net worth (exclusive
of home, home furnishings, and automobiles) with his spouse of $225,000,
without regard to an investment in the Program, and an individual or
combined taxable income of $60,000 or more for the previous year and an
expectation of an individual or combined taxable income of $60,000 or more
for each of the current year and the succeeding year; 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 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 1998 (with respect to investments in the PDC 1998 designated
Partnerships) or in 1999 (with respect to the PDC 1999 designated
Partnerships), or in 2000 (with respect to the PDC 2000 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 1998 (with respect to investments in the PDC 1998 designated
Partnerships) or in 1999 (with respect to the PDC 1999 designated
Partnerships), or in 2000 (with respect to the PDC 2000 designated
Partnerships) of not less than $200,000.
- 30 -
<PAGE>
A resident of South Dakota or 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, (iii)
or an individual or joint minimum net worth (exclusive of home, home
furnishing, and automobile with his or her spouse of $225,000 without
regard to an investment in the Program, and an individual or combined
taxable income of $60,000 or more for the previous year and an expectation
of an individual or combined taxable income of $60,000 or more for each of
the current year and the succeeding 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
- 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
- 31 -
<PAGE>
(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 each
Partnership will be the contributions of the Investor Partners
($1,500,000 ranging to $15,000,000) and the contribution of the Managing
General Partner in cash ($326,250 ranging to $3,262,500) for a total
amount of $1,826,250 if 75 Units are sold ranging to $18,262,500 if 7,50
Units are sold.
Use of Proceeds
A total of 7,500 Units is being offered to fund up to twelve
Partnerships over a three-year period. In order to fund any particular
Partnership, a minimum of 75 Units ($1,500,000) (125 Units or $2,500,000
with respect to each of PDC 1998-D Limited Partnership, PDC 1999-D Limited
Partnership, and PDC 2000-D Limited Partnership) must be sold with respect
to that Partnership. The following table presents information respecting
the financing of a Partnership in four different circumstances: (1) if 750
Units ($15,000,000) are sold, the maximum number of Units which can be
sold for any Partnership, designated as PDC 1998 [1999 or 2000] -A, -B, or
- -C Limited Partnership (2) if the minimum 75 Units ($1,500,000) as are
sold with request to any Partnership designated as PDC 1998 [1999 or 2000]
- -A, -B, or -C Limited Partnership, (3) if 1,250 units ($25,000,000) are
sold for any -D designated Partnerships, and (4) if 125 units ($2,500,000)
and sold, the minimum number of Units which can be sold for any -D
designated Partnership. 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:
- 32 -<PAGE>
<TABLE>
<S> <S> <S> <S> <S> <S> <S> <S> <S>
750 Units 75 Units 1250 Units 125 Units
Sold (3) %(1) Sold %(1) Sold %(1) Sold %1
Total
Partnership
Capital $18,262,500 100.0% $1,826,250 100.0% $30,437,500 100.0% $3,043,750 100.0%
Less: Public
offering expenses
Dealer Manager
fee and
sales
commission
(2)(3) $1,575,000 8.6% $ 157,500 8.6% $2,625,000 8.6% $262,500 8.6%
Less:
Management
fee to managing
general
partners $375,000 2.1% $37,500 2.1% $625,000 2.1% $62,500 2.1%
Amount
available for
investment $16,312,500 89.3% $1,631,250 89.3% $27,187,500 89.3% $2,718,750 89.3%
<FN>
____________________
(1) The percentage is based upon total Investor Partners' Capital
Contributions and the Managing General Partner's Capital
Contribution.
(2) This information is presented for all Partnerships designated or
1998-A through -C Limited Partnership, PDC 1999-A through -C Limited
Partnerships, and PDC 2000-A through -C Limited Partnership. Each
of these Partnerships may sell a maximum of 750 Units ($15,000,000)
and a minimum of 75 Units ($1,500,000).
(3) This information is presented for PDC 1998-D Limited Partnership,
PDC 1999-D Limited Partnership, and PDC 2000-D Limited Partnership.
Each of these Partnerships may sell a maximum of 1,250 Unit
($25,000,000) and a minimum Units ($2,500,000).
(4) PDC Securities Incorporated, an Affiliate of the Managing General
Partner, may reallow in whole or in part up to $1,500,000 (if 750
Units are sold; $2,500,000 for each of PDC 1998-D Limited
Partnership, PDC 1999-D Limited Partnership, and PDC 2000-D Limited
Partnership) ranging to $150,000 (if the minimum number of Units is
sold $250,000 for each of PDC 1998-D Limited Partnership, PDC 1999-D
Limited Partnership, PDC 2000-D Limited Partnership) for sales
commissions, reimbursement of due diligence expenses, marketing
support fees and other compensation payable to other NASD-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 $7,500 if the minimum
number of Units ($12,500 for each of PDC 1998-D, PDC 1999-D and PDC
2000-D Limited Partnership) is sold ranging to $75,000 if the
maximum number of Units is sold ($125,000 for each of PDC 1998-D
Limited Partnership, PDC 1999-D Limited Partnership, and PDC 2000
Limited Partnership). Such payments will be made in cash solely on
the amount of initial Subscriptions.
(5) 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.
(6) Included herein is the Cost to the Partnerships of acquiring
Prospects, which may include Prospects acquired from the Managing
General Partner.
</TABLE>
- 33 -<PAGE>
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%
<FN>
____________________
(1) The allocations and distributions to the Investor Partners and to
the Managing General Partner may vary during the ten years of the
Partnership well operations commencing six months after the close of
a Partnership for any Partnership that fails to meet the
Partnership's performance standard. See "Revenues -- Revision to
Sharing Agreements", immediately below. Additionally, if the
Managing General Partner must increase its Capital Contribution
above its required cash investment of 21-3/4% of Subscriptions to
cover tangible drilling and Lease Costs, the Managing General
Partner's share of the profit and losses and cash available for
distribution will be increased to equal its percentage investment,
and the investor partners' share will correspondingly be decreased.
</TABLE>
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.
- 34 -
<PAGE>
Revenues
Natural Gas Revenues; Sales Proceeds. Revenues from natural gas
production and gain or loss from the sale or other disposition of
productive wells and Leases will be allocated 80% to the Investor Partners
and 20% to the Managing General Partner. The revenues to be allocated are
subject to the "Revision to Sharing Arrangement," immediately below, and
to revisions due to increases in the Managing General Partners's Capital
Contribution to cover tangible drilling and Lease Costs.
Revision to Sharing Arrangements. Partnership profits and losses
will generally be allotted 80% to the Investor Partners and 20% to the
Managing General Partner throughout the term of each partnership; however,
the Partnerships are structured to enhance investor cash distributions
during the first ten years of Partnership well operations commencing six
months after the close of a Partnership for any Partnership which fails to
meet the performance standard described below. If the performance
standard is not fulfilled by a particular Partnership, that Partnership's
sharing arrangement will be modified for up to a ten-year period
commencing six months after the closing date of that Partnership and
ending ten years later.
The performance standard is as follows: If the Average Annual Rate
of Return, as defined below, to the Investor Partners is less than 12.8%
of their Subscriptions, the allocation rate of all items of profit and
loss and cash available for distribution for Investor Partners will be
increased by ten percentage points above the then-current sharing
arrangements for Investor Partners and the allocation rate with respect to
such items for the Managing General Partner will be decreased by ten
percentage points below the then-current sharing arrangements for the
Managing General Partner, until the Average Annual Rate of Return shall
have increased to 12.8% or more, or until ten years and six months shall
have expired from the closing date of the Partnership, whichever event
shall occur sooner. Average Annual Rate of Return for purposes of this
preferred sharing arrangement is defined as (1) the sum of the cash
distributions, estimated initial tax savings of 28% of investor
subscriptions, and estimated tax savings from depletion based on a tax
rate of 28%, realized for a $10,000 investment in the Partnership, divided
by (2) $10,000 multiplied by the number of years (less six months) which
have elapsed since the closing of the Partnership. Thus Investor Partners
may receive up to 90% of Partnership distributions during the revision
period. To the extent that the sharing arrangements are revised in any
particular year, the allocations of the revenue to the Investor Partner
will increase accordingly and the allocation of revenues to the Managing
General Partner will correspondingly decrease. The above referenced
revised sharing arrangement policy is not, and should not be considered by
any Investor Partner to be, any form of guarantee or assurance of a rate
of return on an investment in the Partnership. The policy is the result
of a contractual agreement by the Managing General Partner as set forth in
paragraph 4.02 of the Partnership Agreement. There is no guarantee or
assurance whatsoever that the Partnership will drill commercially
successful gas wells or that the cash distributions to the Partners,
including any cash distributions pursuant to policy, will achieve a 12.8%
rate of return.
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.
Sale of Equipment. All revenues from sales of equipment will be
allocated 100% to the Managing General Partner.
- 35 -<PAGE>
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, Tangible Well Costs, 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 the
Partnership's share of all Leases, Tangible Well Costs, and gathering line
Costs. If such costs exceed the Managing General Partner's required 21-
3/4% Capital Contributions, the Managing General Partner's will invest
additional cash in the Partnerships on its Capital Contribution. If the
Managing General Partner's Capital Contribution exceeds 21-3/4% of
Subscriptions, the Partnership's sharing arrangements of all items of
profit and loss and cash available for distribution will be modified to
equal for the Managing General Partner the percentage arrived at by
dividing the Capital Contribution of the Managing General Partner by the
by the Capital Available for Investment. The Investor Partners'
allocations of such items will be revised accordingly.
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, and in such circumstances the sharing
arrangements of all items of profit and loss and cash available for
distribution will be modified if necessary to equal the percentage Capital
Contributions of the Managing General Partner when divided by the Capital
Available for Investment; the Investor Partners' share of such items will
be revised accordingly.
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.
- 36 -<PAGE>
<TABLE>
<S> <S> <S>
Managing
Investor General
Partners(4) Partner(4)
Partnership Costs
Broker-dealer Commissions and Expenses(1) 100% 0%
Management Fee . . . . . . . . . . . . . . . . 100% 0%
Undeveloped Lease Costs. . . . . . . . . . . . 0% 100%
Tangible Well Costs. . . . . . . . . . . . . . 0% 100%
Intangible Drilling and Development Costs 100% 0%
Total Drilling and Completion Costs. . . . . . 80% 20%
Operating Costs(2) . . . . . . . . . . . . . . 80% 20%
Direct Costs(3). . . . . . . . . . . . . . . . 80% 20%
Administrative Costs . . . . . . . . . . . . . 0% 100%
Partnership Revenues
Sale of Oil and Gas Production . . . . . . . . 80% 20%
Sale of Productive Properties(5) . . . . . . . 80% 20%
Sale of Equipment. . . . . . . . . . . . . . . 0% 100%
Sale of Undeveloped Leases . . . . . . . . . . 80% 20%
Interest Income. . . . . . . . . . . . . . . . 80% 20%
<FN>
(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" and "-- Costs -- Lease Costs, Drilling and
Completion, and Gathering Line Costs".
(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.
</TABLE>
The Managing General Partner estimates that Direct Costs allocable
to the Investor Partners for the initial 12 months of their operations
will be approximately $8,000 if minimum Subscriptions ($1,500,000) are
received (representing 0.5% of aggregate Partnership capital); and
approximately $292,000 if maximum Subscriptions ($150,000,000) are
received (representing 0.2% of aggregate Partnership capital). The
- 37 -
<PAGE>
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
(75 Units) (7,500 Units)
Administrative Costs(1). . . . . . . . . . . . . $ -0- $ -0-
Total Administrative Costs . . . . . . . $ -0- $ -0-
Direct Costs:
Audit and Tax Preparation. . . . . . . . . . $5,000 $120,000
Independent Engineering Reports. . . . . . . 2,000 130,000
Materials, Supplies and Other. . . . . . . . 1,000 42,000
Total Direct Costs . . . . . . . . . . . $8,000 $292,000
</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
1995 1996 1997
Partnership % of % of % of
Name Amount Subscrip- Amount Subscrip- Amount Subscrip-
tions tions tions
PDC 1995-A 10,622 0.52% 6,973 .34% 5,562 .27%
PDC 1995-B 11,950 0.44% 8,046 .30% 6,421 .24%
PDC 1995-C 11,750 0.50% 8,064 .34% 6,303 .27%
PDC 1995-D 12,750 0.17% 17,674 .23% 19,864 .26%
PDC 1996-A - - 8,145 .56% 6,807 .46%
PDC 1996-B - - 8,945 .48% 8,626 .46%
PDC 1996-C - - 9,634 .46% 8,487 .40%
PDC 1996-D - - 13,013 .16% 19,260 .24%
PDC 1997-A - - - - 8,729 .34%
PDC 1997-B - - - - 9,218 .34%
PDC 1997-C - - - - 11,682 .30%
PDC 1997-D - - - - 16,791 .11%
Administrative Costs
1995 1996 1997
Partnership % of % of % of
Name Amount Subscrip- Amount Subscrip- Amount Subscrip-
tions tions tions
PDC 1995-A - - 0 0.00% 0 0.00%
PDC 1995-B - - 0 0.00% 0 0.00%
PDC 1995-C - - 0 0.00% 0 0.00%
PDC 1995-D - - 0 0.00% 0 0.00%
PDC 1996-A - - 0 0.00% 0 0.00%
PDC 1996-B - - 0 0.00% 0 0.00%
PDC 1996-C - - 0 0.00% 0 0.00%
PDC 1996-D - - 0 0.00% 0 0.00%
PDC 1997-A - - - - 0 0.00%
PDC 1997-B - - - - 0 0.00%
PDC 1997-C(1) - - - - 0 0.00%
PDC 1997-D(2) - - - - 0 0.00%
___________________
- 38 -<PAGE>
<FN>
(1) Partnership funded in November 1997.
(2) Partnership funded in December 1997.
</TABLE>
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
- 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 and
decrease for the Managing General Partner in view of the
revised sharing arrangement policy and may decrease for
Investor Partners and increase for the Managing General
Partner if the Managing General Partner invests capital above
its minimum Capital Contribution to cover additional tangible
drilling and Lease Costs.
- 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 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, the Managing General Partner will revise
Partnership sharing arrangements during the ten year revision period if
the average annual rate of return does not equal established goals. See
"Revenues" -- Revision to Sharing Arrangements," above.
- 39 -
<PAGE>
THE ABOVE-REFERENCED REVISED SHARING ARRANGEMENT POLICY IS NOT, AND SHOULD
NOT BE CONSIDERED BY ANY INVESTOR PARTNER TO BE, ANY FORM OF GUARANTEE OR
ASSURANCE OF A RATE OF RETURN ON AN INVESTMENT IN THE PARTNERSHIP. THE
POLICY IS THE RESULT OF A CONTRACTUAL AGREEMENT BY THE MANAGING GENERAL
PARTNER AS SET FORTH IN PARAGRAPH 4.02 OF THE PARTNERSHIP AGREEMENT.
THERE IS NO GUARANTEE OR ASSURANCE WHATSOEVER THAT THE PARTNERSHIP WILL
DRILL COMMERCIALLY SUCCESSFUL GAS WELLS OR THAT THE CASH DISTRIBUTIONS TO
THE PARTNERS, INCLUDING ANY CASH DISTRIBUTIONS PURSUANT TO THE POLICY,
WILL ACHIEVE A 12.8% RATE OF RETURN. 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.
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 Competitive industry
Partner rates rates(3)
- 40 -
<PAGE>
Managing General Operator's Per-Well $300 per well per
Partner Charges month
Managing General Direct Costs Cost(3)
Partner
Managing General Payment for equipment Competitive prices(3)
Partner and supplies, gas marketing,
Affiliates and other services(4)
Affiliate Brokerage sales commi- 10.5% of Subscriptions
ssion reimbursement of $157,500 ranging to
due diligence and $15.75 million (5)
marketing support
expenses; wholesaling fee
<FN>
_____________________
(1) The Managing General Partner will contribute to each Partnership an
amount equal to at least 21-3/4% of the aggregate contributions of
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 revised sharing arrangement policy, and if the Managing
General Partner invests additional capital to fund tangible drilling
and Lease Costs "discussed above".
(2) The one-time fee will range from $37,500 if the minimum number of
Units is sold to $3,750,000 if the maximum number of Units is sold.
(3) Cannot be quantified at the present time.
(4) Some of the gas produced by the Partnership may be marketed by Riley
Natural Gas Company ("Riley"), a subsidiary of the Managing General
Partner.
(5) 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 $15,750,000 if the maximum number of Units is
sold ranging to $157,500 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 $750,000 if the maximum
number of Units is sold to $7,500 if the minimum number of Units is
sold.
</TABLE>
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 $37,500 if the
minimum number of Units is sold ranging to $3,750,000 if the maximum
number of Units is sold. Since a maximum of $15 million ($25 million with
respect to each of the PDC 1998-D Limited Partnership, PDC 1999-D Limited
- 41 -<PAGE>
Partnership and PDC 2000-D Limited Partnership) of Units can be sold in
any individual Partnership, the maximum amount of the Management Fee with
respect to any individual Partnership would be $375,000 ($625,000 with
respect to each of PDC 1998-D Limited Partnership, PDC 1999-D Limited
Partnership, and PDC 2000-D Limited Partnership).
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 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. In
those cases where the Partnership acquires less than a 50% Working
Interest in a Prospect, a party other than the Managing General Partner
may be retained to drill, complete, and operate wells on such project. The
Managing General Partner may 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 annually 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 in the Appalachian
Basin the Partnership elects to complete, the fee for intangible drilling
costs 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 intangible drilling cost fee 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. With respect to Michigan Basin Antrim wells, the Partnerships
will pay an intangible drilling cost fee of $138 per foot for the first
1,000 feet of well depth plus $22 per foot for each additional foot below
1,000 feet to the deepest penetration of the well; for each well which
the Partnerships elect not to complete, an amount equal to $60 per foot
for the first 1,000 feet of well depth, plus $12 per foot for each
additional foot below 1,000 feet to the deepest penetration of the well.
- 42 -
<PAGE>
In addition, in both areas the Partnership will pay the Cost of the
Prospect, as defined and tangible costs of drilling and completing the
Partnership wells. 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
will be acquired from one of the following sources: offering memoranda or
prospectuses for private or public drilling programs, quoted rates,
published rates on costs 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 per well average
monthly drilling overhead rate for gas wells in the area where they are
located as published by Ernst & Young in their 1996 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 as so published is currently $4,945 per well per
month for wells up to 5,000 feet in depth and $3,462 per well per month
for wells 5,000 feet to 10,000 feet in depth in the Appalachian Basin and
$6,060 per well in per month for wells up to 5,000 feet in the Michigan
Basin. 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. In the event the Managing General
Partner determines to conduct its drilling activities in other
geographical areas or other geologic zones, the prospectus will be
supplemented to discuss the different areas or zones and the costs
involved in conducting drilling activities in those areas or zones.
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. The Managing General Partner
intends to market some of the gas produced through Riley, its subsidiary.
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 $15,750,000
if the maximum number of Units is sold ranging to $157,500 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
- 43 -
<PAGE>
sale of the Units, reimbursement of due diligence and marketing support
expenses, and other compensation, but will retain the wholesaling fees of
$750,000 ranging to $75,000.
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 up to 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, Michigan, Pennsylvania, and Ohio. The
Managing General Partner may conduct Partnership operations in New York,
Kentucky, Indiana, Kansas, Montana, Wyoming and/or Oklahoma, as it may
deem advisable. The Partnerships intend to apply most if not 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
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 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 an average annual
rate of return equal to a minimum of 12.8% of their
Subscriptions for each of the ten years of Partnership life
beginning 6 months after the closing of the Partnership.
(2) to preserve and protect the Partnership capital by investing
in seven or more natural gas wells to provide diversification
and to reduce the adverse impact of dry holes and substandard
wells;
(3) 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.
(4) to develop long-lived natural gas reserves 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.
- 44 -<PAGE>
The Investor Partners should be aware that distributions will
decrease over time 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
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 up
to 100% of the Working Interest in the Prospects;
(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, either by
itself or in conjunction with other parties, 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
- 45 -
<PAGE>
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.
- 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
17%.
- 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 other shallow Upper Devonian and Mississippian
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, western Pennsylvania to develop the Medina and Whirlpool
reservoirs, and Michigan to develop the Antrim Formation. The Managing
General Partner reserves the right to conduct Partnership operations in
New York, Kentucky, Indiana, Kansas, Montana, Wyoming, and/or Oklahoma
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.
- 46 -
<PAGE>
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 up to 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 of such royalty interests for all Prospects of a particular
Partnership will not exceed 17%. In its discretion the Managing General
Partner may acquire less than 100% of the Working Interest provided that
costs are reduced proportionately. 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
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. 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
- 47 -
<PAGE>
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
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. 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, 1997, 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. 42 2,700
Doddridge Co. 4 170
Harrison Co. 11 1,190
Lewis Co. 10 1,200
Marion Co. 22 1,200
Monongalia Co. 21 1,250
Taylor Co. 91 4,380
Preston Co. 47 6,370
Upshur Co. 0 0
Gilmer Co. 1 150
Mercer Co. 31 2,850
Ohio
Wayne Co. 92 2,975
Pennsylvania
Clearfield Co. 49 7,130
Fayette Co. 48 7,900
Mercer 18 1,550
Michigan
Alcona Co. 67 3,900
Oscoda Co. 318 12,250
Alpena Co. 256 14,700
Total 1,128 71,865
</TABLE>
- 48 -<PAGE>
In addition, PDC expects to acquire additional acreage on an ongoing
basis throughout 1998, 1999 and 2000 and beyond for the Program and future
partnerships.
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.
In 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.
- 49 -
<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 single 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 and Southern Pennsylvania. Wells to be drilled in this area
are located in Clearfield and Fayette Counties, 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 and 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
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 Elk 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
- 50 -<PAGE>
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.
Western Pennsylvania. Prospects to be drilled in Western
Pennsylvania will target gas reserves contained in the Silurian aged
Medina and Whirlpool Reservoirs. The dominant gas reservoirs in the are
the uppermost sands of the Medina Group, the Thorold and Grimsby
Sandstones. The Whirlpool Sand, located at the base of the Medina Group,
is considered a secondary objective. Occasionally, gas reservoir may be
found in the Cabot Head Sand but this reservoir is not well developed in
the local prospect area. Several hundred successful wells have been
drilled to the south of the prospect area by Atlas Resources, Inc., and to
the north by Vista Resources, Quaker State, Douglas Oil & Gas and others.
Mitchell Energy and Mark Resources drilled several wells in the immediate
prospect area confirming the presence of commercial gas reserves from
Medina reservoirs very similar to those found to the north and south.
The Medina and Whirlpool 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
cratonic 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 western Pennsylvania is marked in the
geologic record by an unconformity on the Ordovician Queenston Shale.
Immediately overlying the Queenston is the Whirlpool Sandstone. This
sand is a fine grained light gray sandstone. The Whirlpool is
interpreted to be strand plain or beachline deposit parallel to
paleoshoreline and perpendicular to the direction of sedimentation to the
southeast. The Whirlpool was deposited atop the Queenston uncomformity.
Post Whirlpool sea level transgression was responsible for the deposition
of prodelta mudstones of the Cabot Head Shale above the Whirlpool. South
of the prospect area there is some development of a sandy member at the
top of this unit. As sediment load increased from the east and southeast,
sea level began retreating to the west and northwest. Delta systems began
to creep into the prospect area from the southeast and east and are
responsible for the deposition of the Grimsby Sandstone. The Grimsby
Sandstone is a delta front deposit and is generally a thin bedded, tight
sandstone unit that is cut by porous channel sequences in some areas.
This sand is light gray to red and the uppermost portion of this unit is
one of the primary pays in the prospect area. As the delta systems
continued to move west-southwest, delta plain deposits were laid down over
the delta front. The Thorold (Red Medina) Sandstone is evidence of the
aerially exposed sands and shales of this sequence. The Red Medina in the
prospect area is thought to be channel type deposits although some case
can be made for bar related features as well. Isopach mapping of the Red
Medina in the prospect area shows a general southeast-northeast trend for
overall sand thickness.
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 50 feet or more. Average porosity values in the pay section
ranges from 6% to 10%. 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.
- 51 -
<PAGE>
Michigan. The Antrim Shale of the Michigan basin has been one of
the most active shallow gas development plays in the U.S. over the last
several years. Approximately 5,000 Antrim wells have been drilled and
successfully completed in northern Michigan with the majority having been
drilled since 1990. The Antrim is composed predominantly of organic rich
black shales of late Devonian age and is found throughout the Michigan
basin, encompassing an area of approximately 30,000 square miles. The
Antrim is productive around the rim of the basin at drilling depths
ranging from 500 to 2,500 feet. The main producing trend is located in
the northern portion of the basin and comprises approximately 20% of the
potential producing region, the remainder of the basin remains relatively
untested. The Antrim is subdivided into four members, the
undifferentiated Upper Antrim, Lachine, Paxton and Norwood. The Lachine
and Norwood are the main pays with the highest organic content. Much of
the total gas in place is adsorbed within the organic shale matrix with
the remainder existing as free gas in matrix pore spaces or in open
natural fractures. These natural fractures are typically water filled.
The wells must be "dewatered" during the initial production phase to
achieve commercial gas production. As the water is produced from the
natural fractures gas production increases, reaching a peak that may
remain flat for several years followed by long term slow decline.
Analysis of currently available production data indicates that the
existing Antrim contain recoverable gas reserves of approximately 500 MMcf
per 100 acres of drainage. While new wells will be drilled in areas
believed to have similar recoveries, there can be no assurance that
Partnership wells will achieve similar results. Development is on a
"project" basis with the project typically consisting of 12 or more gas
wells, three separate piping systems for produced gas, water collection
and lift gas, as well as a water disposal well and compression facility.
Gas production from the Antrim Shale was first reported in northern
Michigan in 1940. Subsequent development was slow until gas pipeline
access across the area was expanded by the Niagran Reef play in the 1970s.
In the late 1970s and early 1980s several operators developed the first
Antrim projects drilled on 40 acre spacing. At the time, completion and
production techniques were somewhat inefficient resulting in marginal
economics. As drilling, completion and production technology improved
over time the Antrim play economics improved dramatically. The relatively
low development cost and low risk make the Antrim a very attractive
development drilling target. In the early 1990's the Antrim play led the
nation in drilling activity and continues today at a brisk pace.
The Devonian aged Antrim Shale was deposited throughout the Michigan
basin and is predominantly composed of organic rich sediments derived from
the continental highlands to the east and west. The Antrim shale subcrop
is circular around the basin and defines the productive updip limit of the
formation. Throughout most of the basin the Antrim is overlain by younger
Devonian and Mississippian aged sediments as well as several hundred feet
of glacial till. The Antrim Shale lies above the Traverse Group and
represents the transition to a clastic environment from a carbonate
environment which dominated most of the Michigan basin's depositional
history.
The Antrim Shale is divided into an upper and lower unit with the
lower Antrim comprised of the Norwood, Paxton and Lachine members. The
organic black shales of the Norwood and Lachine are the dominant producing
horizons in the area and are separated by the light gray Paxton shales.
The upper unit of the Antrim is comprised of the basal green-gray shales
of the Ellsworth overlain by the brown pyritic shales of the upper Antrim.
In some areas the upper Antrim produces gas and is considered a secondary
target for wells drilled in the prospect area. Thickness of both the
Lachine and Norwood black shales is somewhat uniform with the Norwood
averaging 20 feet and the Lachine averaging approximately 80 feet in
thickness.
- 52 -
<PAGE>
The Antrim is both source rock and reservoir with thermal maturation
of kerogen responsible for the bulk of Antrim gas generated. The Antrim
is an unconventional reservoir when gas storage mechanisms are considered.
In conventional reservoirs gas is stored in the available pore spaces in
the rock, while in the Antrim reservoir most of the gas is adsorbed on the
shale matrix and preserved organic matter, with only small amounts stored
in the fracture pore space. Antrim production is found in areas where
natural fractures are developed, providing reservoir permeability
sufficient to produce the adsorbed gas. Generally, the productive areas
are found from the Antrim subcrop down to depths of approximately 2,500
feet. Below this depth open fractures are generally not present and
production rates from wells below this depth have not been commercial.
The mechanism for fracture development is believed to be a combination of
structural forces as well as loading and unloading stress caused by
glaciation. Migrating fluids entered the fractures allowing the critical
pathways to remain open. Gas stored in the shale matrix does not migrate
to the wellbore until fluid is removed from the fractures and reservoir
pressures are reduced. As the Antrim dewaters, fluids are produced from
the fractures and reservoir pressures are lowered, increasing the relative
gas permeability of the reservoir. At this point gas production starts
and will typically increase over time reaching a peak six to eighteen
months into the productive life of the well. Initially, gas production
increases as water production decreases, with peak gas production having
been found in existing wells when gas to water production ratios are
approximately 1:1.
Approximately 5,000 wells have been drilled in northern Michigan
targeting gas reserves in the Devonian age Antrim Shale. Average recovery
for the Antrim play as a whole is estimated to be approximately 500 MMcf
per 100 acres of drainage. Thus, ultimate recovery per well is dependant
upon well spacing and the development of fracture networks to effectively
drain the reservoir. Production profiles vary depending upon the quality
of well. The typical Antrim production profile begins with initial
production in the range of 20 to 50 Mcfd and production inclines to a peak
of approximately 115 to 150 Mcfd in six to eighteen months. At this point
production may remain relatively flat for one to three years with
production then declining at a rate of less than 10 percent per year.
Wells that reach a peak of 100 Mcfd or less may remain flat for a longer
period while the most productive wells, those producing in excess of 250
Mcfd may begin their decline earlier. The productive life of these wells
can be 15 to 20 years or more. Initial water production rates may be
several hundred barrels of water per day (bwpd), declining as gas
production increases to less than 10 bwpd. Early Antrim projects drilled
in the 1960's and 1970's are in production today, evidence of the long
productive life of these wells. The average curve for the entire Antrim
play includes many wells drilled on 40 acre spacing, ineffectively
completed and produced, thus dragging the overall average downward
compared to results from well drilled in the 1990's. Many of the recently
drilled Antrim projects are producing 200 to 300 Mcfd per well and
estimated ultimate recovery will be in the range of 400 to 750 MMcf or
greater per well. Advances over the past several years in completion and
production methods, as well as drilling wells on 80 to 160 acre well
spacing have greatly increased production and ultimate recovery per well.
Nonetheless, because the Partnership will participate in new wells, there
can be no assurance of the actual level of Partnership production or
reserves.
Petroleum Development Corporation currently has under lease or
option approximately 35,000 acres in Michigan prospective for Antrim
development. The initial project well may be exploratory by strict
definition in that it could be located more than one mile from current
production. Each well drilled thereafter, based upon successful initial
results, will be developmental. Pipeline access to competitive gas
markets exist in each area under consideration for drilling. Gas price
approximates NYMEX plus $0.22 with third party charges of approximately
$0.30 downstream of the compression facility for gathering and processing.
- 53 -
<PAGE>
Leases in this area may have total royalty and override burden ranging
from 12.5% to 20.0%, but average royalty and override per well on a
program basis shall not exceed 17% as specified in the prospectus. (See
"Acquisition of Undeveloped Prospects".) PDC will retain no royalty or
overriding interest. PDC is currently consolidating its lease position in
the area, initiating the permit process for proposed wells and obtaining
pipeline rights of way. Currently, no Antrim prospects have been selected
for drilling by future Partnerships, nor is it certain that any Antrim
wells will be drilled by any Partnership.
The production operations for Antrim wells are different than that
for Appalachian Basin wells. This is due to the complicated and labor
intensive operation of the compression, dehydration and water disposal
facilities, as well as operation of the three gathering systems necessary
for efficient production operations. The operational and field
supervision services necessary during the production phase of Antrim wells
is over and above normal production services provided for typical
Appalachian Basin wells. These additional non-routine production services
will be billed to the Partnership at direct cost if performed by an
unaffiliated third party or at industry competitive rates if provided by
the managing general partner. (See "Drilling and Operating Agreement".)
Drilling and Completion Phase
- Most Partnership wells in the Appalachian Basin are expected
to be development wells 3,000 to 5,500 feet deep.
- Most Partnership wells in the Michigan Basin are expected to
development wells 800-1,200 feet in depth.
- The Partnership will drill all wells prior to March 31, 1999
for all Partnerships designated "PDC 1998-_ Limited
Partnership" and prior to March 31, 2000 for all
Partnerships designated "PDC 1999-_ Limited Partnership", and
prior to March 31, 2001 for all Partnerships designated "PDC
2000-_ 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 Appalachian Basin wells will
be drilled to the 3,000 to 5,500 depth and most Michigan Basin wells will
be drilled to the depth of 800 to 1,200 feet to target gas production.
Some shallower or deeper development Prospects may be drilled in these
areas, and if wells are drilled in other areas it is likely that well
depths will differ. After drilling 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 31, 1999 for
Partnerships designated "PDC 1998-_ Limited Partnership", prior to March
31, 2000 for Partnerships designated "PDC 1999-_ Limited Partnership", and
prior to March 31, 2001 for Partnerships designated "PDC 2000-_ Limited
Partnership".
- 54 -
<PAGE>
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 Appalachian wells will be
drilled at least to a depth of at least 2,000 feet and most Michigan wells
will be drilled to a depth of at least 800 feet. 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. Additionally, with respect to those Prospects as to
which the Partnership owns less than a 50% Working Interest, it is
possible that the majority owner of such Prospects will select the
operator for the wells drilled on such Prospects and that the operator may
not be the Managing General Partner. In the event another company acts as
operator, the Managing General Partner will monitor the performance and
activities of the Operator, participate as the Partnership's
representative in decision-making with regard to the joint venture
activities, and otherwise represent the Partnership with regard to the
activities of the joint venture. Where someone other than the Managing
General Partner serves as Operator, 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. Prices of wells operated by third parties may exceed
the footage based rates specified for Michigan.
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 Appalachian Basin 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.
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 intends to utilize the
services of Riley, its subsidiary, in marketing the gas produced by the
Partnership wells. 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 may 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."
- 55 -
<PAGE>
Drilling and Operating Agreement.
- On wells where the Managing General Partner is Operator, it
will have full control over most Partnerships' wells.
- The operator must commence drilling wells within 180 days
after funding of the Partnership, but not later than March 31,
1999 for Partnerships designated "PDC 1998-_ Limited
Partnership", March 31, 2000 for Partnerships designated "PDC
1999-_ Limited Partnership", and March 31, 2001 for
Partnerships designated "PDC 2000-_ Limited Partnership".
- With respect to completed Appalachian Basin wells, the
Partnerships will pay intangible 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; plus the actual extra completion
costs 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; 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.
- With respect to Michigan Basin Antrim wells, the Partnerships
will pay intangible drilling fees of $138 per foot for the
first 1,000 feet of well depth plus $22 per foot for each
additional foot below 1,000 feet to the deepest penetration of
the well; plus in each case the actual extra 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; for each well which the Partnerships elect not to
complete, an amount equal to $60 per foot for the first 1,000
feet of well depth, plus $12 per foot for each additional foot
below 1,000 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 month for accounting, engineering, management, and
general and administrative expenses. In addition, Michigan
wells will have a monthly cost for operation of compression,
water disposal, gas injection and other facilities.
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. Under the terms of the Agreement, the Managing General
Partner may subcontract certain of those responsibilities as Operator for
Partnership wells. The Managing General Partner will retain
responsibility for work performed by subcontractors as set forth in this
prospectus. It is possible that the Managing General Partner will not be
selected as operator on those Prospects in which the Partnership owns less
than a 50% Working Interest.
- 56 -
<PAGE>
Where the duties of operator are subcontracted to an independent
third party, the cost of the wells to the partnership will be determined
by the actual third party costs, plus Managing General Partner's charges
for supervision, engineering, geology, accounting and other services and
the fixed rate overhead charge for the area where the well is located.
These charges are expected to be comparable to the rates in this
Prospectus for the Appalachian and Michigan Basin wells.
The Partnership will pay a proportionate share of total lease,
development, and operating costs, and will be entitled to receive a
proportionate share of production subject only to royalties and overriding
royalties. At the discretion of the Managing General Partner, the
partnership may enter into Joint Ventures which allow a functional
allocation of tangible, intangible and lease costs, where each joint
venturer is responsible for its overhead costs provided the partnership's
interest in the revenues and income of such a joint venture is
proportional to its contribution to the total cost of such venture. It is
anticipated that the Partnerships, PDC, and other third party joint
venturers will share the cost of the Michigan Antrim projects. The
Partnership will be allocated the well cost with the additional project
costs for multiple flow lines, saltwater injection well, equipment for the
central production facility and Leases allocated by the other joint
venture partners through the use of a tax partnership. In return for
contribution of the well cost to an Antrim project, the Partnerships will
acquire a 55% Working Interest in the project. Remaining Working Interest
will be allocated to the parties bearing the project costs for multiple
flowlines, leases, salt water injection well, and equipment for the
central production facility. Michigan Antrim project Leases are unitized
for the purpose of payment of royalties, distribution of working interest
revenue and allocation of project production expenses. Project working
interest revenue and project production expenses are allocated to working
interest owners based on the number of net wells drilled, completed and
placed into production, expressed as a percentage of the total number of
wells then producing in a project proportional to their ownership
interest. To the extent that a Partnership drills and pays for less than
the total number of wells in a project, its overall Working Interest in
the project will be proportionately reduced. 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
therefore 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.
- 57 -
<PAGE>
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 31, 1999 for Partnerships designated "PDC
1998-_ Limited Partnership", March 31, 2000 for Partnerships designated
"PDC 1999-_ Limited Partnership", and March 31, 2001 for Partnerships
designated "PDC 2000-_ 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 secure
the 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 Appalachian Basin
wells, where the Managing General Partner serves as operator as follows:
1) The Cost of the Prospect, as defined; and
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
cost 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 cost for work required by state law in the
event an intermediate or third string of surface casing
is run, as specified above and in each cases 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.
Each Partnership will bear its proportionate share of cost of
drilling and completing or drilling and abandoning Michigan Basin wells,
where the Managing General Partner serves as operator as follows:
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<PAGE>
1) The Cost of the Prospect, as defined; and
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 $138 per foot for the first
1,000 feet of well depth plus $22 per foot for each
additional foot below 1,000 feet to the deepest
penetration of the well; plus in each case the actual
extra 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 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 1,000 feet of well depth plus $12 per foot for
each additional foot below 1,000 feet to the deepest
penetration of the well, as specified above and in each
case actual additional costs for work required by state
law in event an intermediate or third string of surface
casing is run, plus the actual costs for directional
drilling services, if required; and
(c) The tangible Costs of drilling and completing the
Partnership wells.
To the extent that a Partnership drills less than 100% of a well in
a Michigan Antrim project, its Drilling and Completion Costs for that well
will be proportionally decreased, as will its interest in the project.
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. Michigan Basin wells will have an
additional monthly charge for the operation of compression, water
disposal, gas injection, and other facilities. Non-routine operations
will be billed to the Partnership at their Cost.
The Partnership will have the right to take in kind and 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.
- 59 -
<PAGE>
The production and accounting charges may be adjusted annually
beginning January 1, 2000 with respect to Partnerships designated "PDC
1998-_ Limited Partnership", January 1, 2001 for Partnerships designated
"PDC 1999-_ Limited Partnership," and January 1, 2002 for Partnerships
designated "PDC 2000-_ 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 may utilize the services
of Riley, its subsidiary, in marketing the gas produced by the Partnership
wells. 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 and MichCon 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.
- 60 -
<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 17% (1)
_________________________
Managing 20% Partnership
General Interest (2) 17.50% 16.60%
Partner
Investor 80% Partnership
Partners Interest (2) 70.00% 66.40%
Third Landowners and Over-
Parties riding Royalties 12.50% 17.00%
100.0% 100.0%
____________________
<FN>
(1) Landowner and other royalty interests payable to unaffiliated third
parties may vary, provided that the weighted average of such royalty
interests for all Prospects of a Partnership shall not exceed 17%.
(2) The revenues to be distributed are subject to the revised sharing
arrangement policy and to revisions if the Managing General Partner
makes a Capital Contribution greater than its 21-3/4% requirement.
</TABLE>
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, 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.
- 61 -
<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
$30,000,000.
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 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 $15 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
in more than 1,200 wells in Tennessee, Ohio, Pennsylvania, Michigan and
West Virginia, PDC's largest insurance claim has been less than $80,000.
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.
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<PAGE>
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 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
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<PAGE>
(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.
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 gas prices, at
times, and there is no way to predict when unfavorable
conditions may exist in the future.
- 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 3.0% 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
Regulatory Commission ("FERC") and Congressional deregulation of the
natural gas industry and gas prices, prices are generally 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.
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<PAGE>
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. 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. Order No. 636 has restructured
the natural gas industry and has made it more competitive. Among other
factors, the supply and demand balance of crude oil and natural gas in
world markets have caused significant variations in the prices of these
products over recent years. Moreover, some legislation that Congress may
consider with respect to oil and gas can be expected to decrease the
demand for the Partnerships' production in the future assuming such
legislation is directed toward decreasing demand for oil and gas rather
than increasing supply. (See "Risk Factors -- Competition, Markets and
Regulation.") Additionally the North American Free Trade Agreement
("NAFTA") eliminated trade and investment barriers in the United States,
Canada, and Mexico, thereby increasing foreign competition for domestic
natural gas production. Moreover, new pipeline projects recently approved
by, or presently pending before, the FERC could substantially increase the
availability of gas imports 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 effect, if any 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, MichCon and
Equitrans. These companies have all traditionally purchased substantial
portions of their supply from West Virginia, Michigan or Pennsylvania
producers. In addition, all are subject to regulations that require them
to transport gas for other end users under certain conditions. Such
regulations are either mandated by the state commissions of West Virginia,
Michigan or Pennsylvania or by the FERC. Transportation on these systems
generally requires that gas delivered meet certain quality standards and
that a tariff be paid for quantities transported.
The Partnership expects to sell gas from its wells to Hope Gas,
Equitable Gas, 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, MichCon or Equitrans.
While in the past these purchases were generally made on the spot market,
Order No. 636 restructured long-term gas supply, by requiring interstate
gas pipelines to separate their merchant activities from their
transportation activities and by requiring LDCs to take a much more
active role in acquiring their own gas supplies. Consequently, pipelines
and LDC's are buying gas directly from gas producers and marketers, and
retail unbundling efforts are causing many end-users to buy their own
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<PAGE>
reserves. Activity by state regulatory commissions to review LDC
procurement practices more carefully and to unbundle retail sales from
transportation has caused gas purchasers to minimize their risks in
acquiring and attaching gas supply and have added to competition in the
natural gas marketplace.
Moreover in Order No. 587 and other initiatives, FERC has required
pipelines to develop electronic communication in order to ensure that the
gas industry is more competitive. Pipelines must provide standardized
access via the internet to information concerning capacity and prices and
standardized procedures are now available for nominating and scheduling
deliveries. The industry also is developing access and integrate all gas
supply and transportation information on a nationwide basis, so as to
create a nation market. Furthermore, parallel developments toward an
electronie marketplace for electric power, mandated by the FERC in Order
No. 888, are serving to create multi-national markets for energy product
generally. 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 expand natural gas markets to improve
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.
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.
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<PAGE>
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 deregulated, and that the gas will
be sold at fair market value.
Sale of natural gas by the Partnerships will be subject to
regulation by governmental regulatory agencies. Generally, the regulatory
agency in the state where a producing gas well is located supervises
production activities and, 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 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, 1997, PDC had approximately 74 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.
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<PAGE>
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, Michigan and
Pennsylvania. The Company currently operates approximately 1,170 wells.
The Company employs four 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
retains drilling contractors, completion subcontractors, 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 two 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:
<TABLE>
<S> <S> <S> <S>
Positions and Held Current
Name Age Offices Held Position Since
James N. Ryan 66 Chairman, Chief November 1983
Executive Officer
and Director
Steven R. Williams 46 President and March 1983
Director
Dale G. Rettinger 53 Chief Financial July 1980
Officer, Executive
Vice President,
Treasurer
and Director
Roger J. Morgan 70 Secretary and November 1969
Director
Vincent F. D'Annunzio 45 Director February 1989
Jeffrey C. Swoveland 42 Director March 1991
Thomas E. Riley 44 Vice President
Marketing and
Acquisitions April 1996
Ersel Morgan 54 Vice President April 1995
Production
Eric Stearns 39 Vice President April 1985
Exploration and
Development
Alan Smith 38 Senior Geologist April 1980
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<PAGE>
Bob Williamson 42 Geologist February 1991
Susan Foster 36 Engineer June 1997
Tom Carpenter 45 Senior Geologist December 1997
</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.
Dale G. Rettinger has served as Vice President and Treasurer of PDC
since July 1980, and was appointed Chief Financial Officer in September
1997. 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.
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.
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.
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.
Thomas Riley has served as Vice President - Gas Marketing and
Acquisitions of PDC since April of 1996. Prior to joining PDC, Mr. Riley
was president of Riley Natural Gas (RNG) a natural gas marketing company
from its inception in 1987. PDC acquired RNG in April, 1996, and Mr.
Riley continues to serve as president of the wholly owned subsidiary.
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.
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.
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<PAGE>
Susan Foster joined PDC on June 2, 1997, as a petroleum engineer.
Ms. Foster has a B.S. degree in Petroleum Engineering from Pennsylvania
State University and has worked as a petroleum engineer for several
Appalachian Basin oil and gas companies.
Tom Carpenter joined PDC on December, 1997, as a Senior Geologist.
Mr. Carpenter has a B.A. degree in geology from Miami University of Ohio
and an M.S. degree in geology from West Virginia University as well as
other post-graduate studies and seminars. Prior to joining PDC Mr.
Carpenter was employed as Manager of Exploration and Development of Alamco
Inc. from 1996-1997, and by Ashland Exploration, Inc. and Shell Oil
Company.
Certain Shareholders of Petroleum Development Corporation
The following table sets forth information as of March 31, 1997,
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(2)
Owned(1)
Fidelity Management 995,000 9.1
James N. Ryan 1,030,474(2) 9.0
Steven R. Williams 649,000(3) 5.7
Dale G. Rettinger 617,834(4) 5.4
Roger J. Morgan 132,504(5) 1.2
Vincent D'Annunzio 53,600(6) 0.5
Jeffrey C. Swoveland 23,550(7) 0.2
All Directors and Officer
as a Group (6 persons) 2,509,962(8) 20.4
<FN>
____________________
(1) The nature of the beneficial ownership for all the shares is sole
voting and investment power. On November 4, 1997, PDC completed a
public sale of 3,500,000 shares of common stock. The tables does
not reflect the results of the sale.
(2) Based upon 10,985,753 shares of PDC Common Stock issued and
outstanding as of September 30, 1997. With respect to each
individual named below, the total number of shares of common stock
deemed to be outstanding equals the sum of the 10,985,753 shares of
stock outstanding plus the number of stock options exercisable
within 60 days. With respect to all directors and officers as a
group, the total number of shares deemed to be outstanding equals
the sum of the 10,985,753 shares outstanding plus the total number
of stock options exercisable within 60 days held by all officers and
directors as a group.
(2) Includes options to purchase 401,000 shares exercisable within 60
days. Excluding 108,000 shares underlying options which are
exercisable after such 60-day period.
(3) Includes options to purchase 391,000 shares exercisable within 60
days. Excluding 108,000 shares underlying options which are
exercisable after such 60-day period.
(4) Includes options to purchase 77,500 shares exercisable within 60
days.
(5) Includes options to purchase 43,600 shares exercisable within 60
days.
(6) Includes options to purchase 23,550 shares exercisable within 60
days.
(7) Includes options to purchase 1,327,650 shares exercisable within 60
days until exercised, these options cannot be voted.
</TABLE>
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.
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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.
- 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, only after either proving a breach in court or reaching a
settlement as providing with the Managing General Partner.
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.
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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
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. 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.
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<PAGE>
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
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.
- 73 -
<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 some or all of the Partnership wells. A
subsidiary of the Managing General Partner may market gas produced from
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 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
- 74 -
<PAGE>
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
bearbitrarily 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 September 30, 1997, 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:
<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 --
- 75 -
<PAGE>
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 -- --
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 36,640 36,389 -- 1,566,615 -- --
- 76 -
<PAGE>
PDC 1995-B 46,441 59,044 -- 1,972,759 -- --
PDC 1995-C 52,862 35,768 -- 2,276,962 -- --
PDC 1995-D 203,927 293,036 8,628,760 -- -- --
PDC 1996-A 64,405 109,573 -- 2,692,045 -- --
PDC 1996-B 67,118 106,300 -- 2,813,259 -- --
PDC 1996-C 98,662 174,509 -- 4,117,286 -- --
PDC 1996-D 382,543 565,628 16,075,000 -- -- --
PDC 1997-A(1) 104,174 179,882 -- 4,351,672 -- --
PDC 1997-B(2) 168,987 297,990 -- 7,052,934 -- --
PDC 1997-C(3) -- -- -- -- -- --
____________________
<FN>
(1) Partnership funded in May 1997.
(2) Partnership funded in September 1997.
(3) Partnership funded in November 1997.
</TABLE>
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
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
- 77 -
<PAGE>
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
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 seven public drilling programs which
have raised a total of $143,271,737. PDC 2000 Drilling Program (the
"Program") is the eighth public drilling program sponsored by PDC as
general partner.
- 78 -
<PAGE>
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.
<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 31.00 75,000 2,325,000 --
Petrowest
Gas Group
1986-A 11/86 4/87 15.00 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 45.30 20,000 906,000 --
PDC 1988-B 11/88 4/89 49.50 20,000 990,000 --
PDC 1988-C 12/88 6/89 78.00 20,000 1,560,000 --
PDC 1989-P 6/89 12/89 89.625 20,000 1,792,500 --
- 79 -
<PAGE>
PDC 1989-A 10/89 4/90 60.50 20,000 1,210,000 --
PDC 1989-B 12/89 6/90 185.50 20,000 3,710,000 --
PDC 1990-A 6/90 11/90 70.30 20,000 1,406,000 --
PDC 1990-B 9/90 1/91 111.05 20,000 2,221,000 --
PDC 1990-C 11/90 5/91 173.90 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 --
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 73.28 20,000 1,465,603 --
PDC 1995-B 9/95 1/96 92.88 20,000 1,857,648 --
PDC 1995-C 11/95 4/96 105.72 20,000 2,114,496 --
PDC 1995-D 12/95 6/96 407.854 20,000 8,157,071 --
PDC 1996-A 6/96 11/96 128.81 20,000 2,576,200 --
PDC 1996-B 9/96 3/97 134.24 20,000 2,684,707 --
PDC 1996-C 11/96 5/97 197.32 20,000 3,946,478 --
PDC 1996-D 12/96 6/97 765.09 20,000 15,301,726 --
PDC 1997-A 5/97 11/97(2) 208.85 20,000 4,166,946 --
PDC 1997-B 9/97 --(3) 337.97 20,000 6,759,470 --
PDC 1997-C 11/97 --(4) 302.16 20,000 6,043,257 --
______________
- 80 -
<PAGE>
<FN>
(1) Cash distribution made each month since date of first distribution.
(2) Partnership closed on May 19, 1997. Wells were drilled in the
second and third quarters of 1997.
(3) Partnership closed on September 9, 1997. Wells were drilled in the
third and fourth quarters of 1997.
(4) Partnership closed on November 10, 1997. Wells to be drilled in the
fourth quarter of 1997 and first quarter of 1998.
</TABLE>
OPERATING RESULTS OBTAINED BY THESE PRIOR PARTNERSHIPS SHOULD NOT BE
CONSIDERED AS INDICATIVE OF THE OPERATING RESULTS OBTAINABLE BY THE
PARTNERSHIPS.
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 September 30, 1997. All of the wells drilled were
Development Wells, except as otherwise noted.
<TABLE>
<S> <S> <S> <S> <S> <S> <S>
Productive Well Table
September 30, 1997
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 1.0
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
- 81 -<PAGE>
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
PDC 1991-C - 12 2 - 11.2 1.5
PDC 1991-D - 21 5 - 20.4 4.4
PDC 1992-A - 12 2 - 11.0 2.0
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 - 11 4 - 10.8 4.0
PDC 1993-C - 15 2 - 13.8 2.0
PDC 1993-D - 13 2 - 12.1 2.0
PDC 1993-E - 34 2 - 33.3 2.0
PDC 1994-A - 9 1 - 8.9 1.0
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 - 8 1 - 7.1 1.0
PDC 1995-B - 8 3 - 7.1 3.0
PDC 1995-C - 12 1 - 9.6 1.0
PDC 1995-D - 42 2 - 37.5 2.0
PDC 1996-A - 14 2 - 11.5 2.0
PDC 1996-B - 15 - - 13.2 -
PDC 1996-C - 22 2 - 17.6 1.9
PDC 1996-D - 79 5 - 63.9 4.4
PDC 1997-A(4) - 21 1 - 19.4 1.0
PDC 1997-B(5) - - - - - -
PDC 1997-C(6) - - - - - -
Total ...... 41 649 65 41 564.8 58.6
_____________________
- 82 -
<PAGE>
<FN>
(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 1997. Wells were drilled during second and
third quarters of 1997.
(5) Partnership funded in September 1997. Wells were drilled during
third and fourth quarters of 1997.
(6) Partnership funded in November 1997. Wells to be drilled in the
fourth quarter of 1997 and the first quarter of 1998.
</TABLE>
OPERATING RESULTS OBTAINED BY THESE PRIOR PARTNERSHIPS SHOULD NOT BE
CONSIDERED AS INDICATIVE OF THE OPERATING RESULTS OBTAINABLE BY THE
PARTNERSHIPS.
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, 1997.
<TABLE>
<S> <S> <S> <S> <S>
Participants' Payout Table
September 30, 1997
Revenues Before Deducting
Operating Costs(3)
Total
Expendi-
Investors' tures Total During Three
Funds Including As of Months Ended
Invested(1) Operating September September
Costs(2) 30, 1997 30, 1997
Pennwest
Petroleum
Group 1984 $2,093,125 $3,134,861 $2,044,491 $ 9,955
Pennwest
Petroleum
Group 1985-A 1,976,250 2,944,970 1,588,047 14,289
Petrowest
Gas Group
1986-A 956,250 1,462,700 904,811 9,235
Petrowest
Gas Group
1987 1,143,250 1,762,304 1,338,430 13,648
Petrowest
Gas Group
1987-B 983,875 1,418,948 701,405 7,904
PDC 1987 454,750 686,602 471,596 5,079
PDC 1988 770,100 1,202,014 999,102 11,080
PDC 1988-B 841,500 1,223,801 504,393 7,145
- 83 -
<PAGE>
PDC 1988-C 1,326,000 1,953,206 983,525 14,679
PDC 1989-P 1,523,625 2,243,379 1,521,805 21,994
PDC 1989-A 1,028,500 1,549,546 1,106,053 14,055
PDC 1989-B 3,153,500 4,421,712 2,277,533 35,347
PDC 1990-A 1,195,100 1,621,151 619,117 8,673
PDC 1990-B 1,887,850 2,631,723 1,305,399 23,008
PDC 1990-C 2,956,300 4,089,874 1,779,291 43,312
PDC 1990-D 3,132,674 4,289,960 1,854,274 39,079
PDC 1991-A 2,328,150 3,205,657 1,720,022 32,624
PDC 1991-B 1,583,975 2,137,907 947,881 20,450
PDC 1991-C 2,325,600 3,158,169 1,443,306 35,990
PDC 1991-D 4,469,725 5,930,840 1,955,127 49,003
PDC 1992-A 2,472,396 3,223,773 782,973 20,137
PDC 1992-B 2,532,246 3,384,421 1,553,885 56,573
PDC 1992-C 5,430,563 7,317,957 3,865,999 170,448
PDC 1993-A 2,647,750 3,740,234 3,117,234 120,882
PDC 1993-B 2,130,620 2,690,381 918,294 31,969
PDC 1993-C 2,665,865 3,366,774 947,859 40,323
PDC 1993-D 2,545,375 3,151,480 960,517 47,935
PDC 1993-E 6,438,950 8,054,701 2,244,607 136,297
PDC 1994-A 1,798,563 2,283,927 599,754 29,316
PDC 1994-B 2,353,579 2,898,977 857,352 52,241
PDC 1994-C 2,052,636 2,500,136 619,884 40,887
PDC 1994-D 6,605,166 8,028,778 1,955,498 144,501
PDC 1995-A 1,282,403 1,577,575 466,795 35,527
PDC 1995-B 1,625,442 1,933,342 327,779 29,201
PDC 1995-C 1,850,184 2,216,772 373,961 38,442
PDC 1995-D 7,137,437 8,427,814 1,406,353 176,098
PDC 1996-A 2,241,294 2,658,007 651,658 103,567
PDC 1996-B 2,335,695 2,739,086 453,033 91,564
PDC 1996-C 3,433,436 4,020,683 340,701 108,308
PDC 1996-D 13,312,502 15,423,073 759,127 284,487
PDC 1997-A(4) 3,625,243 4,166,946 - -
- 84 -
<PAGE>
PDC 1997-B(5) 5,880,739 6,759,470 - -
PDC 1997-C(6) - - - -
_____________________
<FN>
(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 1997; wells were drilled during second and third quarters of 1997;
first revenue distribution commenced in November 1997.
(5) Partnership funded in September 1997; wells were drilled during the third and fourth quarters
of 1997; first revenue distribution to commence in March, 1998.
(6) Partnership funded in November 1997; wells to be drilled in the fourth quarter of 1997 and
the first quarter of 1998.
</TABLE>
OPERATING RESULTS OBTAINED BY THESE PRIOR PARTNERSHIPS SHOULD NOT BE CONSIDERED
AS INDICATIVE OF THE OPERATING RESULTS OBTAINABLE BY THE PARTNERSHIPS.
- 85 -
<PAGE>
<TABLE>
<S> <S> <S> <S> <S> <S> <S> <S>
Participants' Net Cash Table
September 30, 1997
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- September September September Sept. ion 29
ing Costs 30, 1997 30, 1997 30, 1997 30, 1997 Tax
(1) (2) Credit
Pennwest
Petroleum
Group
1984 $2,093,125 $2,462,500 $1,372,130 $ 541 $1,302,628 $ 541 $483,817
Pennwest
Petroleum
Group
1985-A 1,976,250 2,325,000 968,077 2,263 924,805 2,263 563,529
Petrowest
Gas Group
1986-A 956,250 1,125,000 567,111 1,536 540,341 1,536 417,065
Petrowest
Gas Group
1987 1,143,250 1,345,000 921,126 3,964 878,506 3,964 456,964
Petrowest
Gas Group
1987-B 983,875 1,157,500 439,957 1,185 413,587 1,185 332,774
PDC 1987 454,750 535,000 319,994 974 302,422 974 211,632
PDC 1988 770,100 906,000 703,088 4,258 666,199 4,258 430,010
PDC
1988-B 841,500 990,000 270,592 930 246,752 930 227,989
PDC
1988-C 1,326,000 1,560,000 590,319 4,228 547,263 4,228 430,664
PDC
1989-P 1,523,625 1,792,500 1,070,926 10,467 993,041 10,467 689,539
PDC
1989-A 1,028,500 1,210,000 766,507 5,784 723,423 5,784 453,719
PDC
1989-B 3,153,500 3,710,000 1,565,821 15,295 1,460,185 15,295 669,905
PDC
1990-A 1,195,100 1,406,000 403,966 2,064 343,753 2,064 117,831
PDC
1990-B 1,887,850 2,221,000 894,677 7,771 856,917 7,771 534,025
PDC
1990-C 2,956,300 3,478,000 1,167,416 23,022 1,098,178 23,022 512,506
- 86 -
<PAGE>
PDC
1990-D 3,132,674 3,685,500 1,249,814 17,941 1,188,947 17,941 684,917
PDC
1991-A 2,328,150 2,739,000 1,253,365 16,830 1,149,900 16,830 716,539
PDC
1991-B 1,583,975 1,863,500 673,474 8,915 644,599 8,915 408,109
PDC
1991-C 2,325,600 2,736,000 1,021,137 20,548 934,537 20,548 601,402
PDC
1991-D 4,469,725 5,258,500 1,282,787 23,667 1,209,775 23,667 768,509
PDC
1992-A 2,472,396 2,908,700 467,900 4,734 389,176 4,734 288,905
PDC
1992-B 2,532,246 2,979,100 1,148,563 35,360 1,087,506 35,360 654,033
PDC
1992-C 5,430,563 6,388,900 2,936,942 117,338 2,814,828 117,338 1,240,024
PDC
1993-A 2,647,750 3,026,000 2,403,000 81,996 2,208,824 81,996 95,917
PDC
1993-B 2,130,620 2,435,000 662,913 17,465 604,006 17,465 --
PDC
1993-C 2,665,865 3,046,700 627,786 20,513 571,400 20,513 --
PDC
1993-D 2,545,375 2,909,000 718,037 32,760 676,799 32,760 --
PDC
1993-E 6,438,950 7,358,800 1,548,706 89,326 1,399,758 89,326 --
PDC
1994-A 1,798,563 2,055,500 371,327 14,049 331,357 14,049 --
PDC
1994-B 2,353,579 2,689,804 648,180 37,771 592,922 37,771 --
PDC
1994-C 2,052,636 2,345,870 465,618 26,779 409,181 26,779 --
PDC
1994-D 6,605,166 7,548,761 1,475,481 95,184 1,288,626 95,184 --
PDC
1995-A 1,282,403 1,465,603 354,822 25,451 306,763 25,451 --
PDC
1995-B 1,625,442 1,857,648 252,085 20,331 196,077 20,331 --
PDC
1995-C
1,850,184 2,114,496 271,685 22,323 214,888 22,323 --
PDC
1995-D 7,137,437 8,157,071 1,135,610 126,709 924,914 126,709 --
PDC
1996-A 2,241,294 2,576,200 569,851 84,493 435,033 84,493 --
- 87 -<PAGE>
PDC
1996-B 2,335,695 2,684,707 398,653 71,576 273,737 71,576 --
PDC
1996-C 3,433,436 3,946,478 284,496 85,244 167,221 85,244 --
PDC
1996-D 13,312,502 15,301,726 637,780 234,426 279,690 234,426 --
PDC
1997-A
(6) 3,625,243 4,166,946 -- -- -- -- --
PDC
1997-B
(7) 5,880,739 6,759,470 -- -- -- -- --
PDC
1997-C
(8) -- -- -- -- -- -- --
_____________________
<FN>
(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 1997; wells were drilled during second and third quarters of 1997;
first revenue distribution commenced in November, 1997.
(7) Partnership funded in September 1997; wells were drilled during the third and fourth quarters
of 1997; first revenue distribution to commence in March, 1998.
(8) Partnership funded in November 1997; wells to be drilled during the fourth quarter of 1997
and first quarter of 1998.
</TABLE>
OPERATING RESULTS OBTAINED BY THESE PRIOR PARTNERSHIPS SHOULD NOT BE
CONSIDERED AS INDICATIVE OF THE OPERATING RESULTS OBTAINABLE BY THE
PARTNERSHIPS.
- 88 -
<PAGE>
<TABLE>
<S> <S> <S> <S>
Managing General Partner's Payout Table
September 30, 1997
Revenues Before Deducting
Operating Costs(2)
Total Total As During Three
Expenditures of September Months Ended
Including 30, 1997 September 30, 1997
Partnership Operating Costs(1)
Pennwest
Petroleum
Group 1984 $ 158,252 $258,414 $ 946
Pennwest
Petroleum
Group
1985-A 146,937 206,029 1,360
Petrowest
Gas Group
1986-A 76,979 143,632 1,574
Petrowest
Gas Group
1987 92,749 205,103 2,264
Petrowest
Gas Group
1987-B 74,682 107,766 1,321
PDC 1987 36,138 73,035 857
PDC 1988 63,250 161,588 1,883
PDC 1988-B 64,412 82,784 1,227
PDC 1988-C 103,801 155,304 2,457
PDC 1989-P 118,067 236,266 3,657
PDC 1989-A 195,768 274,348 3,514
PDC 1989-B 509,051 545,449 8,837
PDC 1990-A 180,415 141,448 2,168
PDC 1990-B 308,714 316,386 5,752
PDC 1990-C 464,649 410,002 10,828
PDC 1990-D 477,333 407,789 9,770
PDC 1991-A 365,270 415,183 8,156
PDC 1991-B 235,473 227,186 5,112
PDC 1991-C 354,848 346,500 8,997
PDC 1991-D 638,479 442,449 12,251
PDC 1992-A 296,250 85,543 -0-
PDC 1992-B 371,931 378,052 14,143
- 89 -
<PAGE>
PDC 1992-C 800,166 896,397 42,568
PDC 1993-A 434,526 675,304 26,644
PDC 1993-B 287,594 193,747 6,890
PDC 1993-C 349,684 166,332 7,882
PDC 1993-D 327,492 179,477 9,400
PDC 1993-E 849,621 433,876 24,505
PDC 1994-A 503,501 143,707 6,964
PDC 1994-B 637,757 207,214 12,397
PDC 1994-C 550,045 153,177 9,971
PDC 1994-D 1,766,397 479,371 34,292
PDC 1995-A 348,160 114,780 8,190
PDC 1995-B 424,606 79,134 6,012
PDC 1995-C 487,971 93,050 9,170
PDC 1995-D 1,851,629 349,571 42,008
PDC 1996-A 580,776 162,913 25,892
PDC 1996-B 597,519 113,258 22,891
PDC 1996-C 872,411 85,176 27,077
PDC 1996-D 3,358,465 189,782 71,122
PDC 1997-A(3) 906,311 -- --
PDC 1997-B(4) 1,470,185 -- --
PDC 1997-C(5) -- -- --
_____________________
<FN>
(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 1997; wells were drilled during first and second quarters of 1997;
first revenue distribution commenced in November 1997.
(4) Partnership funded in September 1997; wells were drilled during third and fourth quarters
of 1997; first revenue distribution to commence in March 1998.
(5) Partnership funded in November 1997; wells to be drilled during the fourth quarter of 1997
and the first quarter of 1998.
</TABLE>
OPERATING RESULTS OBTAINED BY THESE PRIOR PARTNERSHIPS SHOULD NOT BE
CONSIDERED AS INDICATIVE OF THE OPERATING RESULTS OBTAINABLE BY THE
PARTNERSHIPS.
- 90 -
<PAGE>
<TABLE>
<S> <S> <S> <S> <S> <S> <S>
Managing General Partner's Net Cash Table
September 30, 1997
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 September September September September Tax
Partnership Costs(1) 30, 1997 30, 1997 30, 1997 30, 1997
Credits
(4)
Pennwest
Petroleum
Group 1984 $ 129,605 $229,767 $ 698 $226,109 $ 698 $25,464
Pennwest
Petroleum
Group
1985-A 122,368 181,460 1,044 179,183 1,044 29,660
Petrowest
Gas Group
1986-A 59,210 125,863 1,168 121,423 1,168 21,951
Petrowest
Gas Group
1987 70,789 183,143 1,754 176,931 1,754 24,051
Petrowest
Gas Group
1987-B 60,921 94,004 967 89,629 967 17,514
PDC 1987 28,158 65,055 641 62,411 641 11,139
PDC 1988 47,684 146,023 1,523 140,474 1,523 22,632
PDC 1988-B 52,105 70,477 900 65,870 900 11,999
PDC 1988-C 82,105 133,608 1,907 126,291 1,907 22,667
PDC 1989-P 94,342 212,541 3,050 199,153 3,050 36,292
PDC 1989-A 114,278 192,859 1,446 182,088 1,446 113,430
PDC 1989-B 350,389 386,786 3,824 360,377 3,824 167,476
PDC 1990-A 132,789 93,822 516 78,769 516 29,458
PDC 1990-B 209,761 217,433 1,943 207,993 1,943 133,506
PDC 1990-C 328,478 273,831 5,755 256,521 5,755 128,126
PDC 1990-D 348,075 278,531 4,485 263,314 4,485 171,229
PDC 1991-A 258,683 308,595 4,207 282,729 4,207 179,135
PDC 1991-B 175,997 167,710 2,229 161,935 2,229 102,027
PDC 1991-C 258,400 250,052 5,137 228,402 5,137 150,350
PDC 1991-D 496,639 300,608 5,916 282,355 5,916 192,127
- 91 -
<PAGE>
PDC 1992-A 274,711 64,004 -0- 44,323 -0- 72,226
PDC 1992-B 281,361 287,482 8,840 275,271 8,840 163,508
PDC 1992-C 603,396 699,626 29,334 675,204 29,334 310,006
PDC 1993-A 294,194 534,972 18,076 492,348 18,076 21,055
PDC 1993-B 236,736 142,889 3,806 129,958 3,806 --
PDC 1993-C 296,207 112,855 4,281 100,478 4,281 --
PDC 1993-D 282,819 134,804 6,597 125,752 6,597 --
PDC 1993-E 715,438 299,693 16,225 266,997 16,225 --
PDC 1994-A 449,641 89,846 3,359 81,072 3,359 --
PDC 1994-B 588,395 157,852 8,990 144,037 8,990 --
PDC 1994-C 513,159 116,291 6,538 102,182 6,538 --
PDC 1994-D 1,651,292 364,266 22,619 317,552 22,619 --
PDC 1995-A 320,601 87,220 5,851 75,205 5,851 --
PDC 1995-B 406,361 60,889 4,135 46,887 4,135 --
PDC 1995-C 462,546 67,624 5,133 53,425 5,133 --
PDC 1995-D 1,784,359 282,301 30,079 229,627 30,079 --
PDC 1996-A 560,324 142,462 21,123 108,758 21,123 --
PDC 1996-B 583,924 99,663 17,894 68,434 17,894 --
PDC 1996-C 858,359 71,124 21,311 41,805 21,311 --
PDC 1996-D 3,328,126 159,444 58,606 69,922 58,606 --
PDC 1997-A(5) 906,311 -- -- -- -- --
PDC 1997-B(6) 1,470,185 -- -- -- -- --
PDC 1997-C(7) -- -- -- -- -- --
<FN>
_____________________
(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 1997; wells were drilled during second and
third quarters of 1997; first revenue distribution commenced in
November, 1997.
(6) Partnership funded in September 1997; wells were drilled during
third and fourth quarters of 1997; first revenue distribution to
commence in March, 1998.
(7) Partnership funded in November 1997; wells to be drilled during the
fourth quarter of 1997 and the first quarter of 1998.
</TABLE>
OPERATING RESULTS OBTAINED BY THESE PRIOR PARTNERSHIPS SHOULD NOT BE
CONSIDERED AS INDICATIVE OF THE OPERATING RESULTS OBTAINABLE BY THE
PARTNERSHIPS.
- 92 -<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 September 30, 1997, 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.
<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% 26.48% 19.65% 65.90% 1.4:1
*Pennwest
Petroleum
Group 1985-A 69.51% 26.81% 24.24% 68.99% 1.4:1
*Petrowest
Gas Group
1986-A 70.10% 29.31% 37.07% 81.49% 1.7:1
*Petrowest
Gas Group
1987 63.09% 35.07% 33.98% 68.94% 2.2:1
*Petrowest
Gas Group
1987-B 68.70% 25.76% 28.75% 63.71% 2.0:1
*PDC 1987 70.30% 20.81% 39.56% 72.84% 2.3:1
*PDC 1988 68.57% 33.07% 47.46% 80.75% 2.7:1
*PDC 1988-B 66.70% 31.14% 23.03% 55.68% 1.8:1
*PDC 1988-C 69.20% 28.66% 27.61% 60.27% 1.9:1
*PDC 1989-P 63.68% 31.99% 38.47% 69.36% 2.3:1
*PDC 1989-A 69.80% 31.98% 37.50% 73.50% 2.3:1
*PDC 1989-B 69.10% 26.36% 18.06% 49.87% 1.6:1
*PDC 1990-A 67.92% 21.64% 8.38% 37.38% 1.2:1
- 93 -
<PAGE>
*PDC 1990-B 71.50% 23.40% 24.04% 55.11% 1.8:1
*PDC 1990-C 70.60% 23.43% 14.74% 46.46% 1.5:1
*PDC 1990-D 69.70% 26.08% 18.58% 51.09% 1.6:1
*PDC 1991-A 69.80% 21.20% 26.16% 54.67% 1.8:1
*PDC 1991-B 67.00% 23.70% 21.90% 50.97% 1.7:1
*PDC 1991-C 69.60% 22.88% 21.98% 51.91% 1.7:1
*PDC 1991-D 69.80% 19.42% 14.61% 43.25% 1.4:1
*PDC 1992-A 68.24% 16.29% 9.93% 36.18% 1.2:1
*PDC 1992-B 69.60% 21.44% 21.95% 51.83% 1.7:1
*PDC 1992-C 69.20% 23.25% 19.41% 49.95% 1.6:1
PDC 1993-A 69.00% 33.51% 3.17% 36.96% 1.1:1
PDC 1993-B 68.10% 17.59% -- 31.26% 0.9:1
PDC 1993-C 68.80% 15.46% -- 30.61% 0.8:1
PDC 1993-D 68.60% 14.34% -- 30.05% 0.8:1
PDC 1993-E 67.60% 16.87% -- 30.92% 0.8:1
PDC 1994-A 87.70% 4.78% -- 35.69% 0.9:1
PDC 1994-B 89.40% 5.96% -- 36.96% 1.0:1
PDC 1994-C 89.70% 4.80% -- 36.56% 0.9:1
PDC 1994-D 89.90% 4.74% -- 36.94% 0.9:1
PDC 1995-A 85.66% 5.91% -- 37.75% 0.9:1
PDC 1995-B 89.02% 2.98% -- 36.75% 0.9:1
PDC 1995-C 89.71% 3.70% -- 37.00% 0.9:1
PDC 1995-D 89.94% 2.90% -- 36.53% 0.9:1
PDC 1996-A 89.94% 2.93% -- 36.54% 0.9:1
PDC 1996-B 86.82% 1.99% -- 35.66% 0.9:1
PDC 1996-C 89.42% 1.12% -- 35.33% 0.9:1
PDC 1996-D 89.49% 0.72% -- 35.21% 0.9:1
PDC 1997-A(4) 89.50% -- -- 35.44% 0.9:1
PDC 1997-B(5) 89.50% -- -- 35.44% 0.9:1
PDC 1997-C(6) 89.50% -- -- 35.44% 0.9:1
<FN>
*Partnerships in existence for over five years.
_____________________
(1) Wells drilled after December 31, 1992 will not qualify for the
credit.
- 94 -<PAGE>
(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 1997.
(5) Partnership funded in September 1997.
(6) Partnership funded in November 1997.
</TABLE>
OPERATING RESULTS OBTAINED BY THESE PRIOR PARTNERSHIPS SHOULD NOT BE
CONSIDERED AS INDICATIVE OF THE OPERATING RESULTS OBTAINABLE BY THE
PARTNERSHIPS.
- 95 -
<PAGE>
<TABLE>
<S> <S> <S> <S> <S> <S> <S>
Percentage of Return on Subscriptions Through
September 30, 1997
From Cash Distributions, Tax Savings from
Deductions and Tax Credits(1)
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) (3) (4) (5)
*Pennwest
Petroleum
Group 1984 52.86% 19.65% 72.51% 50.25% 122.76% 12/6
*Pennwest
Petroleum 39.62% 24.24% 63.86% 48.75% 112.61% 11/7
Group 1985-A
**Petrowest
Gas Group 47.87% 37.07% 84.94% 48.42% 133.36% 10/6
1986
**Petrowest
Gas Group 65.23% 33.98% 99.21% 38.90% 138.10% 9/9
1987
**Petrowest
Gas Group
1987-B 35.71% 28.75% 64.45% 38.96% 103.42% 9/6
**PDC 1987 56.36% 39.56% 95.92% 41.64% 137.56% 9/4
**PDC 1988 73.05% 47.46% 120.51% 37.28% 157.79% 8/10
**PDC 1988-B 24.92% 23.03% 47.95% 36.66% 84.61% 8/6
**PDC 1988-C 35.08% 27.61% 62.68% 36.67% 99.35% 8/4
**PDC 1989-P 55.06% 38.47% 93.53% 34.89% 128.43% 7/10
**PDC 1989-A 59.73% 37.50% 97.22% 40.00% 137.22% 7/6
**PDC 1989-B 39.32% 18.06% 57.38% 35.81% 93.19% 7/4
**PDC 1990-A 24.45% 8.38% 32.83% 32.05% 64.88% 6/11
**PDC 1990-B 38.55% 24.04% 62.60% 35.06% 97.66% 6/9
**PDC 1990-C 31.50% 14.74% 46.23% 35.73% 81.96% 6/5
**PDC 1990-D 32.21% 18.58% 50.79% 36.50% 87.29% 6/4
**PDC 1991-A 42.00% 26.16% 68.16% 32.51% 100.67% 5/11
**PDC 1991-B 34.51% 21.90% 56.41% 33.07% 89.48% 5/8
**PDC 1991-C 34.08% 21.98% 56.06% 33.93% 89.99% 5/6
**PDC 1991-D 22.96% 14.61% 37.57% 32.63% 70.20% 5/4
**PDC 1992-A 13.38% 9.93% 23.32% 30.02% 53.33% 4/11
**PDC 1992-B 36.38% 21.95% 58.33% 33.87% 92.21% 4/9
- 96 -
<PAGE>
**PDC 1992-C 43.81% 19.41% 63.22% 34.54% 97.76% 4/6
**PDC 1993-A 72.59% 3.17% 75.76% 37.79% 113.55% 4/4
**PDC 1993-B 24.75% -- 24.75% 35.26% 60.01% 3/11
**PDC 1993-C 18.70% -- 18.70% 34.61% 53.32% 3/8
**PDC 1993-D 23.14% -- 23.14% 34.05% 57.18% 3/6
**PDC 1993-E 18.98% -- 18.98% 34.92% 53.90% 3/3
**PDC 1994-A 15.92% -- 15.92% 39.69% 55.61% 2/11
**PDC 1994-B 21.74% -- 21.74% 40.96% 62.70% 2/8
**PDC 1994-C 17.21% -- 17.21% 40.56% 57.77% 2/6
**PDC 1994-D 16.84% -- 16.84% 40.94% 57.78% 2/4
**PDC 1995-A 20.70% -- 20.70% 41.75% 62.45% 2/0
**PDC 1995-B 10.45% -- 10.45% 40.75% 51.19% 1/9
**PDC 1995-C 10.05% -- 10.05% 41.00% 51.06% 1/6
**PDC 1995-D 11.30% -- 11.30% 40.53% 51.83% 1/4
**PDC 1996-A 16.89% -- 16.89% 40.54% 57.43% 0/11
**PDC 1996-B 10.20% -- 10.20% 39.66% 49.85% 0/7
**PDC 1996-C 4.24% -- 4.24% 39.33% 43.57% 0/5
**PDC 1996-D 1.83% -- 1.83% 39.21% 41.04% 0
**PDC 1997-A(6) -- -- -- 39.02% 39.02% 0
**PDC 1997-B(7) -- -- -- 39.02% 39.02% 0
**PDC 1997-C(8) -- -- -- 39.02% 39.02% 0
<FN>
* Program contains oil & gas production
** Program contains gas production
_____________________
(1) This table assumes investors were able to fully utilize all tax
benefits at the maximum marginal Federal rate plus an assumed state
rate of 4%
(2) Cash distributions to investors divided by investors' initial
investment.
(3) Credit earned on qualified production. Wells drilled after December
31, 1992 do not qualify for the credit.
(4) Tax savings from deductions assuming investor is in the highest
marginal bracket. Rates used were 54% in 1984, 1985 and 1986, 42.5%
in 1987, 37% in 1988, 1989 and 1990, 35% in 1991 and 1992, 40% in
1993, and 43.6% in 1994 and thereafter.
(5) This column represents the sum of the percentage amounts set forth
in columns 1, 2, and 4 of this table.
(6) Partnership funded in May 1997; wells were drilled during second and
third quarters of 1997; first revenue distribution commenced in
November, 1997.
(7) Partnership funded in September 1997; wells were drilled during
third and fourth quarter of 1997; first revenue distribution to
commence in March, 1998.
(8) Partnership funded in November 1997; wells to be drilled during the
fourth quarter of 1997 and the first quarter of 1998.
</TABLE>
OPERATING RESULTS OBTAINED BY THESE PRIOR PARTNERSHIPS SHOULD NOT BE
CONSIDERED AS INDICATIVE OF THE OPERATING RESULTS OBTAINABLE BY THE
PARTNERSHIPS.
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<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, 1997. The information presented has been
derived from reports prepared by an independent petroleum consultant,
Wright & Company, Inc. and by the Managing General Partner's
petroleum engineers as noted below.
<TABLE>
<S> <S> <S> <S> <S> <S> <S>
Partnership Proved Reserves and Future Net Revenues
as of January 1, 1997(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(2) Proved Developed -- 1,053,751 $ 3,199,030 $ 867,363
Proved Undeveloped -- -- -- --
Totals -- 1,053,751 $ 3,199,030 $ 867,363
PDC 1989-B(2) Proved Developed -- 1,523,428 $ 4,375,498 $1,803,869
Proved Undeveloped -- -- -- --
Totals -- 1,523,428 $ 4,375,498 $1,803,869
PDC 1990-A(2) Proved Developed -- 351,277 $ 855,311 $ 397,176
Proved Undeveloped -- -- -- --
Totals -- 351,277 $ 855,311 $ 397,176
PDC 1990-B(2) Proved Developed -- 1,503,931 $ 4,361,395 $1,216,798
Proved Undeveloped -- -- -- --
Totals -- 1,503,931 $ 4,361,395 $1,216,798
PDC 1990-C(2) Proved Developed -- 2,459,651 $ 7,847,450 $2,579,798
Proved Undeveloped -- -- -- --
Totals -- 2,459,651 $ 7,847,450 $2,579,798
PDC 1990-D(2) Proved Developed -- 2,461,028 $ 7,155,206 $2,494,063
Proved Undeveloped -- -- -- --
Totals -- 2,461,028 $ 7,155,206 $2,494,063
PDC 1991-A(2) Proved Developed -- 1,516,963 $ 4,267,156 $1,450,680
Proved Undeveloped -- -- -- --
Totals -- 1,516,963 $ 4,267,156 $1,450,680
PDC 1991-B(2) Proved Developed -- 1,228,980 $ 3,768,580 $1,389,570
Proved Undeveloped -- -- -- --
Totals -- 1,228,980 $ 3,768,580 $1,389,570
PDC 1991-C(2) Proved Developed -- 1,804,612 $ 5,154,448 $1,758,534
Proved Undeveloped -- -- -- --
Totals -- 1,804,612 $ 5,154,448 $1,758,534
PDC 1991-D(2) Proved Developed -- 2,568,623 $ 7,363,205 $2,497,937
Proved Undeveloped -- -- -- --
Totals -- 2,568,623 $ 7,363,205 $2,497,937
PDC 1992-A(2) Proved Developed -- 717,047 $ 1,645,734 $ 574,320
Proved Undeveloped -- -- -- --
Totals -- 717,047 $ 1,645,734 $ 574,320
- 98 -
<PAGE>
PDC 1992-B(2) Proved Developed -- 2,795,855 $ 8,493,112 $3,019,073
Proved Undeveloped -- -- -- --
Totals -- 2,795,855 $ 8,493,112 $3,019,073
PDC 1992-C(2) Proved Developed -- 5,195,584 $15,873,230 $6,912,866
Proved Undeveloped -- -- -- --
Totals -- 5,195,584 $15,873,230 $6,912,866
PDC 1993-A(2) Proved Developed -- 3,242,395 $10,156,210 $3,996,614
Proved Undeveloped -- -- -- --
Totals -- 3,242,395 $10,156,210 $3,996,614
PDC 1993-B(2) Proved Developed -- 1,558,074 $ 4,532,343 $1,688,012
Proved Undeveloped -- -- -- --
Totals -- 1,558,074 $ 4,532,343 $1,688,012
PDC 1993-C(2) Proved Developed -- 2,346,745 $ 7,106,115 $2,156,639
Proved Undeveloped -- -- -- --
Totals -- 2,346,745 $ 7,106,115 $2,156,639
PDC 1993-D(2) Proved Developed -- 1,995,315 $ 6,418,324 $2,115,957
Proved Undeveloped -- -- -- --
Totals -- 1,995,315 $ 6,418,324 $2,115,957
PDC 1993-E(2) Proved Developed -- 4,744,139 $11,803,490 $4,032,980
Proved Undeveloped -- -- -- --
Totals -- 4,744,139 $11,803,490 $4,032,980
PDC 1994-A(2) Proved Developed -- 1,376,864 $ 3,741,853 $1,315,508
Proved Undeveloped -- -- -- --
Totals -- 1,376,864 $ 3,741,853 $1,315,508
PDC 1994-B(2) Proved Developed -- 1,644,796 $ 4,449,524 $1,960,122
Proved Undeveloped -- -- -- --
Totals -- 1,644,796 $ 4,449,524 $1,960,122
PDC 1994-C(2) Proved Developed -- 1,240,268 $ 3,382,889 $1,213,688
Proved Undeveloped -- -- -- --
Totals -- 1,240,268 $ 3,382,889 $1,213,688
PDC 1994-D(3) Proved Developed -- 4,599,443 $11,573,240 $5,039,515
Proved Undeveloped -- -- -- --
Totals -- 4,599,443 $11,573,240 $5,039,515
PDC 1995-A(3) Proved Developed -- 1,146,889 $ 3,379,354 $1,477,427
Proved Undeveloped -- -- -- --
Totals -- 1,146,889 $ 3,379,354 $1,477,427
PDC 1995-B(3) Proved Developed -- 753,301 $ 2,037,076 $ 767,400
Proved Undeveloped -- -- -- --
Totals -- 753,301 $ 2,037,076 $ 767,400
PDC 1995-C(3) Proved Developed -- 1,033,449 $ 2,760,416 $1,175,676
Proved Undeveloped -- -- -- --
Totals -- 1,033,449 $ 2,760,416 $1,175,676
PDC 1995-D(3) Proved Developed -- 5,013,250 $15,729,080 $7,655,215
Proved Undeveloped -- -- -- --
Totals -- 5,013,250 $15,729,080 $7,655,215
PDC 1996-A(3) Proved Developed -- 2,334,224 $ 7,899,104 $3,810,423
Proved Undeveloped -- -- -- --
Totals -- 2,334,224 $ 7,899,104 $3,810,423
PDC 1996-B(3) Proved Developed -- 2,377,133 $ 7,626,874 $3,712,711
Proved Undeveloped -- -- -- --
Totals -- 2,377,133 $ 7,626,874 $3,712,711
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<PAGE>
PDC 1996-C(3) Proved Developed -- 2,522,541 $ 8,249,101 $4,031,239
Proved Undeveloped -- -- -- --
Totals -- 2,522,541 $ 8,249,101 $4,031,239
PDC 1996-D(4) Proved Developed -- -- -- --
Proved Undeveloped -- -- -- --
Totals -- -- -- --
PDC 1997-A(4) Proved Developed -- -- -- --
Proved Undeveloped -- -- -- --
Totals -- -- -- --
PDC 1997-B(4) Proved Developed -- -- -- --
Proved Undeveloped -- -- -- --
Totals -- -- -- --
PDC 1997-C(4) Proved Developed -- -- -- --
Proved Undeveloped -- -- -- --
Totals -- -- -- --
<FN>
____________________
(1) For the Partnerships PDC 1989-A through PDC 1992-C and from 1994-A
through 1997-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.
(2) Reserve reports prepared by the Managing General Partner's petroleum
engineers.
(3) Reserve reports prepared by an independent petroleum consultant,
Wright & Company, Inc.
(4) The wells of these Partnerships were drilled after December 31,
1996; therefore, reserve studies have not been conducted.
</TABLE>
OPERATING RESULTS OBTAINED BY THESE PRIOR PARTNERSHIPS SHOULD NOT BE
CONSIDERED AS INDICATIVE OF THE OPERATING RESULTS OBTAINABLE BY THE
PARTNERSHIPS.
TAX CONSIDERATIONS
The full tax opinion of Duane, Morris & Heckscher LLP 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 Duane, Morris &
Heckscher LLP , 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.
- 100 -
<PAGE>
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 Tax Relief Act of 1997 (the "1997
Act"), 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. 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.
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 or as a "publicly traded partnership. 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 1998 with respect to the
Partnerships designated "PDC 1998-_ Limited Partnership", in 1999 with
respect to the Partnerships designated "PDC 1999-_ Limited Partnership",
and in 2000 with respect to the Partnerships designated "PDC 2000-_
Limited Partnership". See "Intangible Drilling and Development Costs
Deductions."
4. Neither the at risk nor the limitations related to the
adjusted basis of an Investor in lies Partnership interest 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."
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<PAGE>
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."
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."
- 102 -<PAGE>
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:
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 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."
5. The Managing General Partner will cause the Partnership to
properly elect to deduct currently all Intangible Drilling and Development
Costs.
6. The Partnership will have a December 31 taxable year and will
report its income on the accrual basis.
7. 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, 1999 for
Partnerships designated "PDC 1998-_ Limited Partnership", March 30, 2000
for Partnerships designated "PDC 1999-_ Limited Partnership", and March
30, 2001 for Partnerships designated "PDC 2000-_ Limited Partnerships".
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.
8. The Drilling and Operating Agreement will be duly executed and
will govern the operation of the Partnership's Wells.
9. Based upon the Managing General Partner's review of its
experience with its previous drilling programs since 1984 (see "Prior
Activities - Tax Deductions and Tax Credits of Participants in Previous
Partnerships", above) and upon the intended operations of the Partnership,
the Managing General Partner has represented 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
- 103 -
<PAGE>
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.
10. The Managing General Partner has represented 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 has represented that any market will ever
exist for the sale of Units. Further, the Units will not be traded on an
established securities market.
11. The Partnership and each Partner will have the objective of
carrying on business for profit and dividing the gain therefrom.
12. The Managing General Partner will not permit 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.
- 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
- 104 -
<PAGE>
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 1998 for Partnerships designated "PDC 1998-_ Limited
Partnership", in 1999 for Partnerships designated "PDC 1999-_
Limited Partnership", and 2000 for Partnerships designated
"PDC 2000-_ 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
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, and self-
employed investors could realize additional tax savings on self-employment
taxes.
- 105 -
<PAGE>
A. Classification of Costs
In general, IDC consists of those costs which in and of themselves
have no salvage value. In previous partnerships sponsored by the Managing
General Partner from 1984 through 1997 (see "Prior Activities - Tax
Deductions and Tax Credits of Participants in Previous Partnerships",
above), 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 1998, the wells for
Partnerships designated "PDC 1998-_ Limited Partnership" must be spudded
by March 30, 1999; in order for the IDC to qualify for deduction in 1999,
the wells for Partnerships designated "PDC 1999-_ Limited Partnership"
must be spudded by March 30, 2000; in order for the IDC to qualify for
deduction in 2000, the wells for Partnerships designated "PDC 2000-_
Limited Partnerships" must be spudded by March 30, 2001; 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 1998 for Partnerships designated "PDC 1998-_
Limited Partnership (or in 1999 for Partnerships designated "PDC 1999-_
Limited Partnership" or in 2000 for Partnerships designated "PDC 2000-_
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
1999 for Partnerships designated "PDC 1998-_ Limited Partnership" (or 2000
for Partnerships designated "PDC 1999-_ Limited Partnership" or 2001 for
Partnerships designated "PDC 2000_- Limited Partnership") are not
deductible in whole or in part until 1999 for Partnerships designated "PDC
1998-_ Limited Partnership" (or 2000 for Partnerships designated "PDC
1999-_ Limited Partnership" or 2001 for Partnerships designated "PDC 2000-
_ Limited Partnership"). Further, to the extent drilling of the
Partnership's wells does not commence by March 30, 1999 for Partnerships
designated "PDC 1998-_ Limited Partnership" (or March 30, 2000 for
Partnerships designated "PDC 1999-_ Limited Partnership" or March 30, 2001
for Partnerships designated "PDC 2000-_ 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.
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
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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
- Investors who are "independent producers" of oil and gas will
be entitled to claim a percentage depletion deduction on
their oil and gas income currently a minimum deduction 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. 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 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 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 a minimum deduction 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
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.
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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. Investor
partners will not be able to claim depreciation deductions because all
tangible costs have been allocated to the Managing General Partner.
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.
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.
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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 loss by the "at risk" basis rules or the
limitations related to a Partner's basis in their Partnership
interest.
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. In general a
Partnership is "at risk" to the extent of the amount of cash and the
adjusted basis of other property contributed to the Partnership. 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 the at risk rules
nor the adjusted 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.
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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
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.
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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.
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
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 producers in taxable years beginning after 1992, the
Energy Policy Act repealed the treatment of percentage depletion as a
preference item for AMT purposes and provided a limited benefit from the
preference on expensing IDC. However, their AMTI may not be reduced by
more than 40% of the AMTI determined without this benefit.
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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 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 there is 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 there is 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.
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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.
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.
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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 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).
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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
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 sponsored by the Managing General
Partner since 1984, and the planned activities of the Program, the
Managing General Partner has represented that the Partnerships will
qualify as "Tax Shelters" under the Code, and will not register them as
such. See "Prior Activities -- Tax Deductions and Tax Credits of
Participants in Previous Partnerships", above.
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.
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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
a summary of all the material terms of the Partnership Agreement, but do
not purport to be complete and in no way amend or modify the Partnership
Agreement.
Responsibility of Managing General Partner
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.
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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.
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
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
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may elect to retain its interest in the Partnership as a Limited Partner
in the 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, 2048 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.
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.
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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.
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.
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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, 1998 with
respect to Partnerships designated "PDC 1998-_ Limited Partnership",
December 31, 1999 with respect to Partnerships designated "PDC 1999-_
Limited Partnership," and December 31, 2000 with respect to Partnerships
designated "PDC 2000-_ 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
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.
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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 a fractional 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
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 the Managing General Partner and by
Additional General Partners. 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. Moreover, 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 the Managing General Partners and by
the Additional General Partners."
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."
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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 (75 Units aggregating $1.5
million; 125 Units aggregating $2.5 million with respect to each of PDC
1998-D Limited Partnership, PDC 1999-D Limited Partnership and PDC 2000-D
Limited Partnership) is sold within the offering period. The term
"maximum" refers to the maximum proceeds of $15 million ($25 million with
respect to PDC 1998-D Limited Partnership, PDC 1999-D Limited Partnership,
and PDC 2000-D Limited Partnership) 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
equal to 0.5% of the Investor Partners' Subscriptions, for an aggregate of
$15,750,000 if the maximum number of 1,250 Units is sold ($157,500 if the
minimum number of 75 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
$1.5 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
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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 75
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 minimum requirement. Any Units purchased by the Managing General
Partner and/or its Affiliates will be held for investment and not for
resale.
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 Duane,
Morris & Heckscher LLP, 1667 "K" Street, N. W., Suite 700, Washington,
D.C. 20006.
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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, 1996 and 1995 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. 333-41977) 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. This Registration Statement, as well as all exhibits and
amendments thereto, have been filed and will be filed electronically with
the Commission through the Electronic Data Gathering Analysis and
Retrieval ("EDGAR") system. Such Registration Statement and all exhibits
and amendments thereto are publicly available through the Commission's
website (http://www.sec.gov). 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:
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.
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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 Available for Investment: The sum of (a) the Subscriptions, net
of the sales commissions, due diligence expenses, marketing support fees
and other compensation, and wholesaling fees, which aggregate 10.5% of
Subscriptions, and the Management Fee and (b) the Capital Contribution of
the Managing General Partner.
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
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.
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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.
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.
- 126 -
<PAGE>
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 whose interests are converted 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.
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, 1998 with respect to Partnerships
designated "PDC 1998-_ Limited Partnership", December 31, 1999 with
respect to Partnerships designated "PDC 1999-_ Limited Partnership", and
December 31, 2000 with respect to Partnerships designated "PDC 2000-_
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.
- 127 -<PAGE>
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 2000 Drilling Program comprised of a series of up to
twelve limited partnerships to be designated as the PDC 1988-A Limited
Partnership, the PDC 1998-B Limited Partnership, the PDC 1998-C Limited
Partnership, PDC 1998-D Limited Partnership, PDC 1999-A Limited
Partnership, PDC 1999-B Limited Partnership, PDC 1999-C Limited
Partnership, PDC 1999-D Limited Partnership, PDC 2000-A Limited
Partnership, PDC 2000-B Limited Partnership, PDC 2000-C Limited
Partnership, and PDC 2000-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 2000 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 2000 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
- 128 -
<PAGE>
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.
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
- 129 -<PAGE>
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:
(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 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.
- 130 -<PAGE>
Unit: An undivided interest of an Investor Partner in the aggregate
interest in the capital and profits of the Partnership.
Well Head Gas Price: The price paid by a gas purchaser for gas produced
from Partnership wells excluding any tax reimbursements or transportation
allowances.
Wholesaling Fee: A fee paid to the representative of the Dealer Manager
who helps introduce and explain the Program to registered representatives
with firms executing a selling agreement with the Dealer Manager for the
Program.
Working Interest: An interest in an oil and gas leasehold which is
subject to some portion of the costs of development, operation, or
maintenance.
- 131 -<PAGE>
PETROLEUM DEVELOPMENT CORPORATION
AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 1996 and 1995
(With Independent Auditors' Report Thereon)
F-1
<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, 1996 and 1995.
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, 1996 and 1995,
in conformity with generally accepted accounting principles.
/s/ KPMG Peat Marwick
Pittsburgh, Pennsylvania
March 13, 1997
F-2
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 1996 and 1995
<TABLE>
<S> <S> <S>
1996 1995
Assets
Current assets:
Cash and cash equivalents (includes
restricted cash of $1,734,900 in 1996) $20,615,400 10,053,600
Notes and accounts receivable 6,696,000 2,016,600
Inventories 567,200 217,900
Prepaid expenses 740,900 868,800
Total current assets 28,619,500 13,156,900
Properties and equipment:
Oil and gas properties (successful
efforts accounting method) 46,525,700 37,992,000
Pipelines 7,186,900 6,851,900
Transportation and other equipment 2,151,200 2,546,900
Land and buildings 1,098,200 849,200
56,962,000 48,240,000
Less accumulated depreciation,
depletion and amortization 22,522,300 21,127,100
34,439,700 27,112,900
Other assets 545,000 350,300
$63,604,200 40,620,100
</TABLE>
AN INVESTOR IN PDC 2000 DRILLING PROGRAM DOES NOT THEREBY ACQUIRE
ANY INTEREST IN THE ASSETS OF PETROLEUM DEVELOPMENT CORPORATION
(Continued)
F-3
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 1996 and 1995
<TABLE>
<S> <S> <S>
1996 1995
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable $ 9,703,800 2,119,100
Accrued taxes 506,000 155,100
Other accrued expenses 1,505,900 1,628,800
Advances for future drilling contracts 18,397,000 10,069,600
Funds held for future distribution 864,000 704,000
Total current liabilities 30,976,700 14,676,600
Long-term debt, excluding
current maturities 5,320,000 2,500,000
Other liabilities 1,094,200 601,700
Deferred income taxes 3,140,800 2,920,900
Commitments and contingencies
Stockholders' equity:
Common stock, par value $.01 per share;
authorized 22,250,000 shares; issued and
outstanding 10,460,753 and 11,208,627 104,600 112,100
Common stock, Class A, par value $.01 per
share; authorized 2,750,000 shares; issued
and outstanding - none - -
Additional paid-in capital 6,617,300 7,019,800
Retained earnings 16,427,400 12,878,000
Unamortized stock award (76,800) (89,000)
Total stockholders' equity 23,072,500 19,920,900
$63,604,200 40,620,100
</TABLE>
See accompanying notes to consolidated financial statements.
F-4
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
December 31, 1996 and 1995
(1) Summary of Significant Accounting Policies
Principles of Consolidation
The accompanying consolidated financial statements 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 financial
statements include its pro rata share of assets and liabilities and
revenues and expenses, respectively, of the limited partnerships in
which it participates.
The Company is involved in two business segments. The different
segments are oil and gas well drilling, production and related
property management and marketing and pipeline operations.
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. An inventory of natural gas is
recorded when gas is purchased in excess of deliveries to customers
and is recorded at the lower of cost or market.
Oil and Gas Properties
Exploration and development costs are accounted for by the successful
efforts method.
The Company assesses impairment of capitalized costs of proved oil and
gas properties by comparing net capitalized costs to undiscounted
future net cash flows on a field-by-field basis using expected
prices. Prices utilized for measurement purposes and expected costs
are held constant. If net capitalized costs exceed undiscounted
future net cash flow, the measurement of impairment is based on
estimated fair value which would consider future discounted cash
flows.
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)
F-5
<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.
Based on the Company's experience, management believes site
restoration, dismantlement and abandonment costs net of salvage to be
immaterial in relation to operating costs. These costs are being
expensed when incurred.
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. These assets are reviewed
for impairment whenever events or changes in circumstances indicate
that the carrying amount of the assets may be recoverable. An
impairment loss based on estimated fair value is recorded when the
review indicates that the related expected future net cash flow
(undiscounted and without interest charges) is less than the carrying
amount of the asset.
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.
During 1995, the Company established split-dollar life insurance
arrangements with certain executive officers. Under these
arrangements, advances are made to these officers equal to the
premiums due. The advances are collateralized by the cash surrender
value of the policies. The Company records as other assets its share
of the cash surrender value of the policies.
(Continued)
F-6
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
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.
Derivatives
Gains and losses related to qualifying hedges of firm commitments or
anticipated transactions through the use of natural gas futures
contracts are deferred and recognized in income or as adjustments of
carrying amounts when the underlying hedged transaction occurs. In
order for futures contracts to qualify as a hedge, there must be
sufficient correlation to the underlying hedged transaction. The
change in the fair value of derivative instruments which do not
qualify for hedging are recognized into income currently.
Stock Compensation
On January 1, 1996, the Company adopted SFAS No. 123, "Accounting for
Stock-Based Compensation," which permits entities to recognize as
expense over the vesting period the fair value of all stock-based
awards on the date of grant. Alternatively, SFAS 123 allows entities
to continue to measure compensation cost for stock-based awards using
the intrinsic value based method of accounting prescribed by APB
Opinion No. 25, "Accounting for Stock Issued to Employees," and to
provide pro forma net income and pro forma earnings per share
disclosures as if the fair value based method defined in SFAS 123 had
been applied. The Company has elected to continue to apply the
provisions of APB 25 and provide the pro forma disclosure provisions
of SFAS 123.
Use of Estimates
Management of the Company has made a number of estimates and
assumptions relating to the reporting of assets and liabilities and
revenues and expenses and the disclosure of contingent assets and
liabilities to prepare these financial statements in conformity with
generally accepted accounting principles. Actual results could
differ from those estimates. Estimates which are particularly
significant to the consolidated financial statements include
estimates of oil and gas reserves and future cash flows from oil and
gas properties.
(2) Notes and Accounts Receivable
The Company held notes receivable from officers, directors and
employees with interest from 8% to 12% as of December 31, 1995 in the
amount of $33,300 of which $200 is current.
Included in other assets are noncurrent notes and accounts receivable
as of December 31, 1996 and 1995, in the amounts of $5,930 and
$168,400, net of the allowance for doubtful accounts of $147,200 and
$368,800, respectively.
The allowance for doubtful current accounts receivable as of December
31, 1996 and 1995 was $140,600 and $20,200, respectively.
(Continued)
F-7<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
(3) Advances for Future Drilling Contracts
Represents funds received from Partnerships and other joint venturers
for drilling activities which have not been completed and,
accordingly, have not yet been recognized as income in accordance
with the Company's income recognition policies.
(4) Long-Term Debt
The company is party to a bank credit agreement dated November 17, 1993
which, as amended, provides a borrowing base of $10,000,000 subject
to adequate natural gas reserve levels. At the request of the
Company, the bank may increase the amount of the commitment to
$20,000,000. The Company has activated $7.5 million of the facility.
As of December 31, 1996 and 1995, the balance outstanding was
$5,320,000 and $2,500,000, respectively. No principal payments are
required under the credit agreement until maturity on December 31,
1999. Interest accrues at prime with LIBOR (London Interbank Market)
rate alternatives available at the discretion of the Company. At
December 31, 1996, interest accrues at prime (8-1/4%) plus 1/4%. The
Company is required to pay a commitment fee of 1/8% to 1/4% on the
unused portion of the credit facility. The loan is secured by
substantially all properties of the Company. The credit agreement
requires, among other things, the existence of satisfactory levels of
natural gas reserves, maintenance of certain working capital and
tangible net worth ratios along with a restriction on the payment of
dividends.
(5) 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, 1996 and 1995 are presented below:
<TABLE>
<S> <S> <S>
1996 1995
Deferred tax assets:
Drilling notes, principally due to
allowance for doubtful accounts $ 465,800 671,300
Investment tax credit carryforwards 45,200 233,300
Alternative minimum tax credit
carryforwards (Section 29) 926,600 909,400
Other 550,800 440,600
Total gross deferred tax assets 1,988,400 2,254,600
Less valuation allowance (926,600) (941,300)
Deferred tax assets 1,061,800 1,313,300
Less current deferred tax assets
(included in prepaid expenses) (376,100) (386,200)
Net non-current deferred
tax assets 685,700 927,100
Deferred tax liabilities:
Plant and equipment, principally
due to differences in
depreciation and amortization (3,826,500) (3,848,000)
Total gross deferred
tax liabilities (3,826,500) (3,848,000)
Net deferred tax liability $(3,140,800) (2,920,900)
</TABLE>
The Company has evaluated each deferred tax asset and has provided a
valuation allowance where it is believed it is more likely than not
that some portion of the asset will not be realized.
F-8
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
The net changes in the total valuation allowance were for the year
ended December 31, 1996 a decrease of $14,700 and for the years ended
December 31, 1995 and 1994 increases of $98,600 and $45,000,
respectively.
At December 31, 1996, the Company has investment tax credit
carryforwards for federal income tax purposes of approximately $45,200
which are available to reduce future federal income taxes through 2000.
In addition, the Company has alternative minimum tax credit
carryforwards (Section 29) of approximately $926,600 which are
available to reduce future federal regular income taxes over an
indefinite period.
(6) Stockholders' Equity
Changes in Stockholders' Equity during 1996 and 1995 are as follows:
<TABLE>
<S> <S> <S> <S> <S> <S> <S>
Common stock
issued
Number Additional
of paid-in Retained Unamortized
shares Amount capital earnings Stock Award Total
Balance
December 31, 1994 11,040,627 $110,400 6,873,600 11,396,500 - 18,380,500
Issuance of common
stock:
Exercise of employee
stock options 78,000 800 45,800 - 46,600
Stock award 90,000 900 100,400 - (101,300) -
Amortization of
stock award - - - - 12,300 12,300
Net income - - - 1,481,500 - 1,481,500
Balance,
December 31, 1995 11,208,627 $112,100 7,019,800 12,878,000 (89,000) 19,920,900
Issuance of common
stock:
Exercise of employee
stock options 230,699 2,300 166,100 - - 168,400
Purchase of subsidiary 236,094 2,300 446,800 - - 449,100
Amortization of stock
award 12,200 12,200
Repurchase and
cancellation of treasury
stock (1,214,667) (12,100) (1,015,400) (1,027,500)
Net income - - - 3,549,400 - 3,549,400
Balance
December 31, 1996 10,460,753 $104,600 6,617,300 16,427,400 (76,800) 23,072,500
</TABLE>
Options
Options amounting to 210,000 shares were granted during 1995 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 vest
over a two year period. The outstanding options expire from 1997 to
2005.
The estimated fair value of the options granted during 1995 was $.67 per
option. The fair value was estimated using the Black-Scholes option
pricing model with the following assumptions: risk-free interest rate
of 5.8%, expected dividend yield of 0%, expected volatility of 51% and
expected life of 7 years.
F-9<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
<TABLE>
<S> <S> <S>
Number
of Shares Average Range
Outstanding December 31, 1994 1,956,000 $0.77 .38 - 1.63
Granted 210,000 $1.13 1.13 - 1.13
Exercised (78,000) $0.60 .56 - .72
Expired (235,350) $0.68 .38 - 1.63
Outstanding December 31, 1995 1,852,650 $0.91 .50 - 1.63
Granted -
Exercised (230,000) $0.72 .50 - 1.125
Expired (40,000) $0.80 .50 - 1.625
Outstanding December 31, 1996 1,582,650 $0.94 .50 - 1.625
</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.
Stock Purchase
On January 31, 1996, the Company purchased 1,200,000 shares of its
common stock pursuant to an option agreement. The option was
obtained in connection with a debt restructuring in 1990. The
company utilized its' revolving credit line to acquire the shares for
$1,000,000 or $0.83 a share. The shares representing approximately
11% of the currently outstanding stock were retired by the Company.
(7) Employee Benefit Plans
In 1995, a total of 90,000 restricted shares of the Company's common
stock were granted to certain employees and are available to them
upon retirement. The market value of shares awarded was $101,300.
This amount was recorded as unamortized stock award and is shown as
a separate component of stockholders' equity. The unamortized stock
award is being amortized to expense over the employees' expected
years to retirement and amounted to $12,200 in 1996 and 1995.
At December 31, 1996 and 1995, the Company has recorded as other assets
$111,800 and $60,000, respectively as its share of the cash surrender
value of the life insurance pledged as collateral for the payment of
premiums on split-dollar life insurance policies owned by certain
executive officers.
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.
F-10
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
(8) Transactions with Affiliates
As part of its duties as well operator, the Company received
$18,234,200 in 1996 and $11,397,000 in 1995 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. The Company provided oil and gas well drilling
services to affiliated partnerships, substantially all of the
Company's oil and gas well drilling operations was for such
partnerships. The Company also provided related services of
operation of wells, reimbursement of syndication costs, management
fees, tax return preparation and other services relating to the
operation of the partnerships. The Company received $6,435,700 in
1996 and $4,003,500 in 1995 for those services. During 1996 and 1995
the Company paid $35,400 and $38,500, respectively to the Corporate
Secretary's law firm for various legal services.
(9) 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.
One customer, Hope Gas Inc., a regulated public utility, accounted
for 16.1% of total revenues in 1996.
The Company is not party to any legal action that would materially
affect the Company's operations or balance sheets.
(10) Acquisitions
On April 1, 1996, the Company acquired Riley Natural Gas Company (RNG),
a privately held gas marketing company in a stock for stock exchange
accounted for as a purchase. The acquisition has substantially
increased the Company's capabilities in the natural gas marketing
area. PDC issued 236,094 shares with a market value of $449,100, for
100% of the outstanding common stock of RNG. Key employees of RNG
have entered into employment contracts with PDC to assure the
continuity of RNG's gas marketing operations.
On August 6, 1996 the Company purchased an interest in 188 oil and gas
wells in West Virginia. The Company utilized its revolving credit
line to finance the purchase. The purchase increased the Company's
oil and gas reserves by 4.3 Bcf of natural gas and 27,000 barrels of
oil, added 12,000 acres of leases to its leasehold inventory and
increased the Company's gathering systems by forty-nine miles. The
purchase price was $3.3 million.
(11) Derivatives and Hedging Activities
The company utilizes commodity based derivative instruments as hedges
to manage a portion of its exposure to price volatility stemming from
its integrated natural gas production and marketing activities.
These instruments consist of natural gas futures contracts traded on
the New York Mercantile Exchange. The futures contracts hedge
committed and anticipated natural gas purchases and sales, generally
forecasted to occur within a 12 month period. The Company does not
hold or issue derivatives for trading or speculative purposes.
F-11
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
As of December 31, 1996, the Company had futures contracts for the sale
of $3,869,900 of natural gas. While these contracts have nominal
carrying value, their fair value, represented by the estimated amount
that would be received upon termination of the contracts, based on
market quotes, was a net value of $217,770 at December 31, 1996.
The Company is required to maintain margin deposits with brokers for
outstanding futures contracts. As of December 31, 1996, cash in the
amount of $1,734,900 was on deposit.
(12) 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>
<S> <S> <S>
Years Ended December 31,
1996 1995
Property acquisition cost:
Proved undeveloped properties $ 543,600 167,800
Producing properties 3,211,800 218,500
Development costs 5,344,900 2,977,700
$9,100,300 3,364,000
</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.
(13) 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,
1996 1995
Proved properties:
Intangible drilling costs $19,572,400 16,582,000
Tangible well equipment 21,999,600 16,831,800
Well equipment leased to others 4,063,600 4,063,600
Undeveloped properties 890,100 514,600
46,525,700 37,992,000
Less accumulated depreciation,
depletion and amortization 15,837,800 14,529,900
$30,687,800 23,462,100
</TABLE>
(Continued)
F-12
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
(14) Net Proved Oil and Gas Reserves (Unaudited)
The proved reserves of oil and gas of the Company as estimated by an
independent petroleum engineer, Wright & Company, Inc. at December
31, 1996 and by the Company's petroleum engineers at December 31,
1995. These reserves have been prepared in compliance with the
Securities and Exchange Commission rules based on year end prices.
Since December 31, 1996 prices have declined to seasonal levels.
An analysis of the change in estimated quantities of oil and gas
reserves, all of which are located within the United States, is
shown below:
<TABLE>
<S> <S> <S>
Oil (BBLS)
1996 1995
Proved developed and
undeveloped reserves:
Beginning of year 140,000 79,000
Revisions of previous estimates (30,000) 72,000
Beginning of year as revised 110,000 151,000
Dispositions (49,000) -
Acquisitions 27,000 -
Production (7,000) (11,000)
End of year 81,000 140,000
Proved developed reserves:
Beginning of year 140,000 79,000
End of year 81,000 140,000
Gas (MCF)
1996 1995
Proved developed and
undeveloped reserves:
Beginning of year 33,829,000 32,225,000
Revisions of previous estimates (1,037,000) 686,000
Beginning of year as revised 32,792,000 32,911,000
New discoveries and extensions 2,613,000 2,119,000
Disposition (127,000) -
Acquisitions 9,529,000 135,000
Production (1,495,000) (1,336,000)
End of year 43,312,000 33,829,000
Proved developed reserves:
Beginning of year 29,326,000 27,746,000
End of year 35,516,000 29,326,000
</TABLE>
(15) 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
computed by applying year-end prices of oil and gas
relating to the Company's proved reserves to the year-end quantities
of those reserves. Future production, development, site restoration
and abandonment 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.
F-13
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
<TABLE>
<S> <S> <S>
Years Ended December 31,
1996 1995
Future estimated cash flows $193,800,000 99,478,000
Future estimated production
and development costs (59,806,000) (29,288,000)
Future estimated income tax expense (33,499,000) (20,004,000)
Future net cash flows 100,495,000 50,186,000
10% annual discount for
estimated timing of cash flows (66,233,000) (29,126,000)
Standardized measure of discounted
future estimated net cash flows $ 34,262,000 21,060,000
</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,
1996 1995
Sales of oil and gas
production, net of
production costs $(3,711,000) (1,938,000)
Net changes in prices
and production costs 42,384,000 17,024,000
Extensions, discoveries
and improved recovery,
less related cost 9,659,000 4,609,000
Acquisitions 17,775,000 294,000
Development costs incurred
during the period 5,345,000 2,978,000
Revisions of previous
quantity estimates (2,902,000) 1,700,000
Changes in estimated
income taxes (13,495,000) (6,054,000)
Accretion of discount (37,107,000) (8,575,000)
Other (4,746,000) (3,423,000)
$ 13,202,000 6,615,000
</TABLE>
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.
F-14
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
(15) Business Segments
Information on the Company by business segment is as follows for the years ended
December 31,:
<TABLE>
<S> <S> <S>
1996 1995
Identifiable Assets:
Drilling and production $54,847,000 39,016,000
Marketing and pipeline 8,005,100 1,067,700
Corporate 752,100 536,400
$63,604,200 40,620,100
Capital Expenditures:
Drilling and production $10,059,900 3,817,700
Marketing and pipeline 124,200 86,900
Corporate 231,400 5,800
$10,415,500 3,910,400
</TABLE>
F-15
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
September 30, 1997 and December 31, 1996
<TABLE>
<S> <S> <S>
1997 1996
(unaudited)
Assets
Current assets:
Cash and cash equivalents $10,302,000 $20,615,400
Accounts and note receivable 5,001,800 6,696,000
Inventories 358,100 567,200
Prepaid expenses 1,485,800 740,900
Total current assets 17,147,700 28,619,500
Properties and equipment 61,407,500 56,962,000
Less accumulated depreciation,
depletion and amortization 23,912,100 22,522,300
37,495,400 34,439,700
Other assets 651,300 545,000
$55,294,400 $63,604,200
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable and accrued expenses $ 9,714,600 $11,715,700
Advances for future drilling contracts 6,164,800 18,397,000
Funds held for future distribution 1,127,000 864,000
Total current liabilities 17,006,400 30,976,700
Long-term debt, excluding
current maturities 3,000,000 5,320,000
Other liabilities 1,310,900 1,094,200
Deferred income taxes 3,515,700 3,140,800
Commitments and contingencies
Stockholders' equity:
Common stock 109,900 104,600
Additional paid-in capital 8,582,800 6,617,300
Warrants outstanding 46,400 -
Retained earnings 21,789,900 16,427,400
Unamortized stock award (67,600) (76,800)
Total stockholders' equity 30,461,400 23,072,500
$55,294,400 $63,604,200
</TABLE>
(Continued)
AN INVESTOR IN PDC 2000 DRILLING PROGRAM DOES NOT THEREBY ACQUIRE ANY
INTEREST IN THE ASSETS OF PETROLEUM DEVELOPMENT CORPORATION
F-16<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, 1996 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, 1997 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, 1997 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, 1997. There has
been no change in commitments and contingencies as described in Note 9 to the
Consolidated Balance Sheet at December 31, 1996.
AN INVESTOR IN PDC 2000 DRILLING PROGRAM DOES NOT THEREBY ACQUIRE ANY INTEREST
IN THE ASSETS OF PETROLEUM DEVELOPMENT CORPORATION
F-17
<PAGE>
APPENDIX A
FORM OF
LIMITED PARTNERSHIP AGREEMENT
OF
PDC 1998-___ LIMITED PARTNERSHIP
[PDC 1999-___ LIMITED PARTNERSHIP]
[PDC 2000-___ LIMITED PARTNERSHIP]
<PAGE>
APPENDIX A
FORM OF
LIMITED PARTNERSHIP AGREEMENT
OF
PDC 1998-___ LIMITED PARTNERSHIP
[PDC 1999-___ LIMITED PARTNERSHIP]
[PDC 2000-___ 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 . . . . . . . . . . . . . . . 1
1.06 Filings . . . . . . . . . . . . . . . . . . . . . 2
1.07 Independent Activities . . . . . . . . . . . . . 2
1.08 Definitions . . . . . . . . . . . . . . . . . . . 2
ARTICLE II: Capitalization. . . . . . . . . . . . . . . . . . 11
2.01 Capital Contributions of the Managing General
Partner and Initial Limited Partner . . . . . . . 11
2.02 Capital Contributions of the Investor
Partners. . . . . . . . . . . . . . . . . . . . . 11
2.03 Additional Contributions. . . . . . . . . . . . . 12
ARTICLE III: Capital Accounts and Allocations. . . . . . . . . 12
3.01 Capital Accounts. . . . . . . . . . . . . . . . . 12
3.02 Allocation of Profits and Losses. . . . . . . . . 14
3.03 Depletion . . . . . . . . . . . . . . . . . . . . 20
3.04 Apportionment Among Partners. . . . . . . . . . . 20
ARTICLE IV: Distributions . . . . . . . . . . . . . . . . . . 21
4.01 Time of Distribution. . . . . . . . . . . . . . . 21
4.02 Distributions . . . . . . . . . . . . . . . . . . 21
4.03 Capital Account Deficits. . . . . . . . . . . . . 22
4.04 Liability Upon Receipt of Distributions . . . . . 22
ARTICLE V: Activities. . . . . . . . . . . . . . . . . . . . 23
5.01 Management. . . . . . . . . . . . . . . . . . . . 23
5.02 Conduct of Operations . . . . . . . . . . . . . . 23
5.03 Acquisition and Sale of Leases. . . . . . . . . . 25
5.04 Title to Leases . . . . . . . . . . . . . . . . . 25
5.05 Farmouts. . . . . . . . . . . . . . . . . . . . . 26
5.06 Release, Abandonment, and Sale or Exchange
of Properties . . . . . . . . . . . . . . . . . . 26
5.07 Certain Transactions. . . . . . . . . . . . . . . 26
ARTICLE VI: Managing General Partner. . . . . . . . . . . . . 30
6.01 Managing General Partner. . . . . . . . . . . . . 30
6.02 Authority of Managing General
Partner . . . . . . . . . . . . . . . . . . . . . 31
6.03 Certain Restrictions on Managing General
Partner's Power and Authority . . . . . . . . . . 32
6.04 Indemnification of Managing General
Partner . . . . . . . . . . . . . . . . . . . . . 34
6.05 Withdrawal. . . . . . . . . . . . . . . . . . . . 35
i<PAGE>
6.06 Management Fee. . . . . . . . . . . . . . . . . . 35
6.07 Tax Matters and Financial Reporting
Partner . . . . . . . . . . . . . . . . . . . . . 35
ARTICLE VII: Investor Partners . . . . . . . . . . . . . . . . 35
7.01 Management. . . . . . . . . . . . . . . . . . . . 35
7.02 Indemnification of Additional
General Partners. . . . . . . . . . . . . . . . . 36
7.03 Assignment of Units . . . . . . . . . . . . . . . 36
7.04 Prohibited Transfers . . . . . . . . . . . . . . 36
7.05 Withdrawal by Investor Partners . . . . . . . . . 38
7.06 Removal of Managing General Partner . . . . . . . 38
7.07 Calling of Meetings . . . . . . . . . . . . . . . 39
7.08 Additional Voting Rights. . . . . . . . . . . . . 39
7.09 Voting by Proxy . . . . . . . . . . . . . . . . . 40
7.10 Conversion of Additional General Partner
Interests into Limited Partner
Interests . . . . . . . . . . . . . . . . . . . . 40
7.11 Unit Repurchase Program . . . . . . . . . . . . . 41
7.12 Liability of Partners . . . . . . . . . . . . . . 42
ARTICLE VIII: Books and Records. . . . . . . . . . . . . . . . .42
8.01 Books and Records . . . . . . . . . . . . . . . . 42
8.02 Reports . . . . . . . . . . . . . . . . . . . . . 43
8.03 Bank Accounts . . . . . . . . . . . . . . . . . . 45
8.04 Federal Income Tax Elections. . . . . . . . . . . 45
ARTICLE IX: Dissolution; Winding-up . . . . . . . . . . . . . 45
9.01 Dissolution . . . . . . . . . . . . . . . . . . . 45
9.02 Liquidation . . . . . . . . . . . . . . . . . . . 46
9.03 Winding-up . . . . . . . . . . . . . . . . . . . 46
ARTICLE X: Power of Attorney . . . . . . . . . . . . . . . . 47
10.01 Managing General Partner as Attorney-in-Fact. . . 47
10.02 Nature as Special Power . . . . . . . . . . . . . 48
ARTICLE XI: Miscellaneous Provisions. . . . . . . . . . . . . 48
11.01 Liability of Parties. . . . . . . . . . . . . . . 48
11.02 Notices . . . . . . . . . . . . . . . . . . . . . 48
11.03 Paragraph Headings. . . . . . . . . . . . . . . . 48
11.04 Severability. . . . . . . . . . . . . . . . . . . 49
11.05 Sole Agreement. . . . . . . . . . . . . . . . . . 49
11.06 Applicable Law. . . . . . . . . . . . . . . . . . 49
11.07 Execution in Counterparts . . . . . . . . . . . . 49
11.08 Waiver of Action for Partition. . . . . . . . . . 49
11.09 Amendments. . . . . . . . . . . . . . . . . . . . 49
11.10 Consent to Allocations and Distributions. . . . . 50
11.11 Ratification. . . . . . . . . . . . . . . . . . . 50
11.12 Substitution of Signature Pages . . . . . . . . . 50
11.13 Incorporation by Reference. . . . . . . . . . . . 50
Signature Page . . . . . . . . . . . . . . . . . .51
ii<PAGE>
FORM OF
LIMITED PARTNERSHIP AGREEMENT
OF PDC 1998-____ LIMITED PARTNERSHIP,
[PDC 1999-____LIMITED PARTNERSHIP,]
[PDC 2000-___ LIMITED PARTNERSHIP]
A WEST VIRGINIA LIMITED PARTNERSHIP
This LIMITED PARTNERSHIP AGREEMENT (the "Agreement") is made as of
this _ day of ___________, 1998 [1999; 2000] 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
1998-_ Limited Partnership, [PDC 1999-_ Limited Partnership; PDC 2000-_
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.
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
$1,500,000 ($2,500,000 with respect to PDC 1998-D Limited Partnership, PDC
1999-D Limited Partnership, and PDC 2000-D Limited Partnership) in Units
1
<PAGE>
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
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
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:
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(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 Available for Investment" shall mean the sum of (a)
Subscriptions, net of total underwriting and brokerage discounts,
commissions, and expenses, up to an aggregate of 10.5% of Subscriptions,
and the Management Fee and (b) the Capital Contribution of the Managing
General Partner.
(h) "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.
(i) "Code" shall mean the Internal Revenue Code of 1986, as
amended from time to time (or any corresponding provisions of succeeding
law).
(j) "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
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
3
<PAGE>
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.
(k) "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.
(l) "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.
(m) "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.
(n) "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 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.
(o) "Dry Hole" shall mean any well abandoned without having
produced oil or gas in commercial quantities.
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<PAGE>
(p) "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.
(q) "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.
(r) "General Partners" shall mean the Additional General Partners
and the Managing General Partner.
(s) "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) 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.
5
<PAGE>
(t) "IDC" shall mean intangible drilling and development costs.
(u) "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.
(v) "Initial Limited Partner" shall mean Steven R. Williams or any
successor to his interest.
(w) "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.
(x) "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.
(y) "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.
(z) "Management Fee" shall mean that fee to which the Managing
General Partner is entitled pursuant to Section 6.06 hereof.
(aa) "Managing General Partner" shall mean Petroleum Development
Corporation or its successors, in their capacity as the Managing General
Partner.
(bb) "Mcf" shall mean one thousand cubic feet of natural gas.
(cc) "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.
(dd) "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).
(ee) "Nonrecourse Liability" shall have the meaning set forth in
Treas. Reg. Sections 1.704-2(b)(3) and 1.752-1(a)(2).
(ff) "Offering Termination Date" shall mean December 31, 1998 with
respect to Partnerships designated "PDC 1998-_ Limited Partnership
(December 31, 1999 with respect to Partnerships designated "PDC 1999-_
Limited Partnership", and December 31, 2000 with respect to Partnerships
designated "PDC 2000-_ Limited Partnerships) or such earlier date as the
Managing General Partner, in its sole and absolute discretion, shall
elect.
6<PAGE>
(gg) "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.
(hh) "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.
(ii) "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.
(jj) "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.
(kk) "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).
(ll) "Partner Nonrecourse Debt" shall have the meaning set forth in
Treas. Reg. Section 1.704-2(b)(4).
(mm) "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).
(nn) "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.
(oo) "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.
(pp) "Partnership Minimum Gain" shall have the meaning set forth in
Treas. Reg. Sections 1.704-2(b)(2) and 1.704-2(d)(1).
7<PAGE>
(qq) "Permitted Transfer" shall mean any transfer of Units
satisfying the provisions of Section 7.03 herein.
(rr) "Person" shall mean any individual, partnership, corporation,
trust, or other entity.
(ss) "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 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.
(tt) "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
8<PAGE>
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.
(uu) "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.
(vv) "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.
(ww) "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.
(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, (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.
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(xx) "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.
(yy) "Reservoir" shall mean a separate structural or stratigraphic
trap containing an accumulation of oil or gas.
(zz) "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 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.
(aaa) "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.
(bbb) "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.
(ccc) "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.
(ddd) "Subscription Agreement" shall mean the Agreement, attached to
the Prospectus as Appendix B, pursuant to which an Investor subscribes to
Units in the Partnership.
10<PAGE>
(eee) "Substituted Investor Partner" shall mean any Person admitted
to the Partnership as an Investor Partner pursuant to Section 7.03(c)
hereof.
(fff) "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).
(ggg) "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.
(hhh) "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.
(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 21-3/4% 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 the event of such additional Capital Contribution,
the Managing General Partner's share of profits and losses and
distributions shall equal the percentage arrived at by dividing the
Managing General Partner's Capital Contribution by the Capital Available
for Investment of the Partnership, except that such percentage may be
revised by Sections 3.02 and 4.02. 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).
(b) The contributions of the Investor Partners pursuant to
subsection 2.02(a) hereof shall be in cash or by check subject to
collection.
11<PAGE>
(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 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
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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
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).
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(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 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 2.01(a) and 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 Managing General
Partner's share of cash distributions is revised pursuant to Section 4.02
the allocations of Profits and Losses of the Partnership shall be
allocated to reflect such revision. Notwithstanding the above
allocations, the following special allocations shall be employed:
(i) irrespective of any revisions effected by Section
2.01(a) or Section 4.02 IDC and recapture of IDC shall
be allocated 100% to the Investor Partners and 0% to the
Managing General Partner;
(ii) irrespective of any revisions effected by Section
2.01(a) or Section 4.02, the following provisions shall
apply: 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;
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(iii) irrespective of any revisions effected by Section
2.01(a) or Section 4.02, the Management Fee shall be
allocated 100% to the Investor Partners and 0% to the
Managing General Partner;
(iv) irrespective of any revisions effected by Section
2.01(a) or Section 4.02, 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) irrespective of any revisions effected by Section
2.01(a) or Section 4.02, Administrative Costs shall be
borne 100% by and allocated 100% to the Managing General
Partner.
(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
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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-
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.
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(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.
(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
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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 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 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:
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(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.
(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.
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(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.
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.
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(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.
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.
(a) Except as otherwise provided below and in Section 2.01(a), 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 the performance
standard as defined below in subsection (b), is not fulfilled by a
particular Partnership, that Partnership's sharing arrangement shall be
modified, as set forth herein, for up to a ten-year period commencing six
months after the closing date of the Partnership and ending ten years
following such closing date.
(b) The performance standard shall be as follows:
(i) If the Average Annual Rate of Return, as defined below,
to the Investor Partners is less than 12.8% of their
subscriptions, the allocation rate of all items of
profit and loss and cash available for distribution for
Investor Partners shall be increased by ten percentage
points above the then-current sharing arrangements for
Investor Partners and the allocation rate with respect
to such items for the Managing General Partner will be
decreased by ten percentage points below the then-
current sharing arrangements for the Managing General
Partner, until the Average Annual Rate of Return shall
have increased to 12.8% or more, or until the ten year
and six months shall have expired from the closing date
of the Partnership, whichever event shall occur sooner.
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(ii) Average Annual Rate of Return for purposes of
this sharing arrangement shall be defined as (1)
the sum of cash distributions, estimated tax
savings of 28% of Subscriptions, and estimated
tax savings from depletion based on a tax rate of
28%, realized for a $10,000 investment in the
Partnership, divided by (2) $10,000 multiplied by
the number of years (less six months) which have
elapsed since the closing of the Partnership.
(c) 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.
(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.
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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 90% 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,
Kentucky, Michigan, Indiana, Kansas, Montana, Wyoming and/or Oklahoma and
(z) the Prospects will be acquired pursuant to an arrangement whereby the
Partnership will acquire up to 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 of such royalty interests for all Prospects of the Partnership
shall not exceed 17%.
(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.
(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
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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, 2000
[with respect to Partnerships designated as "PDC 1998-_ Limited
Partnership", January 1, 2001 with respect to Partnerships designated as
"PDC 1999-_ Limited Partnership", and January 1, 2002 with respect to
Partnerships designated as "PDC 2000-_ 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.
(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.
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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.
(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.
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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.
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.
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(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 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.
27<PAGE>
(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 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.
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(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 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
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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.
(3) he 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
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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
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;
31<PAGE>
(e) Compromise, sue, or defend any and all claims in favor of or
against the Partnership;
(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,
(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
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(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
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.
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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, the
Massachusetts Securities Division, and the Tennessee Securities Division
or respective state securities division, 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.
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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.
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;
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(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
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
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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.
(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.
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(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.
(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.
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(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 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
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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
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 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.
(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
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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 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 available borrowing capacity under its loan
agreements 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
borrowing capacity 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 limitations imposed by the Code or insufficent
borrowing capacity under 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 to the extent that the Managing General
Partner is unable to repurchase all Units tendered at the same time by
Partner of any Partnership, the Managing General Partnership shall
repurchase those particular Units on a pro rata basis.
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(d) The offer price which the Managing General Partner shall make
shall be a cash amount equal to four 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 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 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;
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<PAGE>
(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 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.
43
<PAGE>
(c) Annually within 120 days after the end of each fiscal year (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 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.
44<PAGE>
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
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, 2048; (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.
45
<PAGE>
(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
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, except
as otherwise revised pursuant to Section 2.01(a) and/or
section 4.02.
(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
46
<PAGE>
(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
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.
47
<PAGE>
(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.
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.
48
<PAGE>
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.
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 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
49<PAGE>
(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.
* * * * *
50
<PAGE>
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 Steven R. Williams
103 East Main Street 103 East Main Street Inc.
Bridgeport, West Virginia 26330 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:_______________________________
_______________________________________
By: Petroleum Development Corporation
By: __________________________________
its______________________________
Attorney-in-Fact
51
<PAGE>
EXHIBIT A
TO
AGREEMENT OF LIMITED PARTNERSHIP
OF
PDC 1998-___ LIMITED PARTNERSHIP,
[PDC 1999-___ LIMITED PARTNERSHIP,]
[PDC 2000-___ LIMITED PARTNERSHIP,]
A WEST VIRGINIA LIMITED PARTNERSHIP
Names and Addresses of Investors Nature of Interest Number of
Units
52
<PAGE>
APPENDIX B TO PROSPECTUS
SUBSCRIPTION AGREEMENT
PDC 1998-_ Limited Partnership
[PDC 1999-_ Limited Partnership]
[PDC 2000-___ Limited Partnership,]
I hereby agree to purchase ______ Unit(s) in the PDC 1998-_ Limited
Partnership [PDC 1999-_ Limited Partnership; PDC 2000-_ 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 1998 [1999; 2000] 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, Alaska, 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, or Washington, 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.
(h) I acknowledge that the investment is not liquid.
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.
(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.
B-1
<PAGE>
(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
[ ] Joint Tenants with Right
of Survivorship
(both persons must sign)
[ ] Tenants in Common (both
[ ] Other _______________
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-4
<PAGE>
APPENDIX C TO PROSPECTUS
PDC 2000 DRILLING PROGRAM
SPECIAL SUBSCRIPTION INSTRUCTIONS
Checks for Units should be made payable to "PNC Bank, N.A. as Escrow
Agent for PDC 1998-_ Limited Partnership [PDC 1999-_ Limited Partnership;
2000-_ 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.
Notice to Alaska Residents.
- Alaska investors are not permitted to make an investment
unless they meet either of the following requirements: the
Alaska purchaser must be (a) a person whose total purchase
does not exceed 5% of his/her net worth if the purchase of
securities is at least $10,000, or (B) a person with income in
excess of $70,000 in the past two years as well as the current
year provided the amount of securities purchased does not
exceed 10% of the current year's expected income.
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
1998 for Partnerships designated "PDC 1998-_ Limited
Partnership" 1999 for Partnerships designated "PDC 1999-_
Limited Partnership" and 2000 for Partnerships designated "PDC
2000-_ 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.
C-1
<PAGE>
- If a Pennsylvania or South Dakota 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 1997 for Partnerships designated "PDC
1998-_ Limited Partnership", 1998 for Partnerships designated
"PDC 1999-_ Limited Partnership" and 1999 for Partnerships
designated "PDC 2000-_ 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.
Additional General Partner Subscribers:
- Except as otherwise provided below,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,
Tennessee, Texas, or Vermont I (i) have an individual or
joint minimum net worth with my spouse of $225,000 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; an
investor in Arizona, Indiana, Iowa, Kansas, Kentucky,
Michigan, Missouri, New Mexico, Ohio, Oklahoma, Oregon, and
Vermont must represent that he has an individual or joint
minimum net worth (exclusive of home, home furnishings, and
automobiles) with his spouse of $225,000, without regard to
an investment in the Program, and an individual or combined
taxable income of $60,000 or more for the previous year and an
expectation of an individual or combined taxable income of
$60,000 or more for each of the current year and the
succeeding year; 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 resident of South Dakota or 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, or (iii) have an individual or joint minimum net worth
(exclusive of home, home furnishings, and automobile) with his
or her spouse of $225,000, without regard to an investment in
the Program, an individual or combined taxable income of
$60,000 or more for the previous year and an expectation of an
individual or combined taxable income of $60,000 or more for
each of the current year and the succeeding year.
- If I am A Michigan, Pennsylvania, or South Dakota resident,
my investment in the Partnership will not be equal to more
than 10% of my net worth.
C-2
<PAGE>
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 1997 for Partnerships designated "PDC 1998-_ Limited
Partnership", 1998 for Partnerships designated "PDC 1999-_
Limited Partnership" and 1999 for Partnerships designated "PDC
2000-_ Limited Partnership" of $120,000 or more, or expects to
have gross income in 1998 for Partnerships designated "PDC
1998-_ Limited Partnership", 1999 for Partnerships designated
"PDC 1999-_ Limited Partnership" and 2000 for Partnerships
designated "PDC 2000-_ 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 1998 for Partnerships designated "PDC
1998-_ Limited Partnership", 1999 for Partnerships designated
"PDC 1999-_ Limited Partnership" and 2000 for Partnerships
designated "PDC 2000-_ 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 1998 for Partnerships designated "PDC 1998-_ Limited
Partnership, 1999 for Partnerships designated "PDC 1999-_
Limited Partnership and 2000 for Partnerships designated "PDC
2000-_ 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
1998 for Partnerships designated "PDC 1998-_ Limited
Partnership", 1999 for Partnerships designated "PDC 1999-_
Limited Partnership" and 2000 for Partnerships designated "PDC
2000-_ Limited Partnership" of not less than $200,000.
- 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 issue or transferee of such security at the time the
certificate evidencing the security is delivered to the issue or
transferee.
C-3
<PAGE>
(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;
(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;
C-4
<PAGE>
(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-5<PAGE>
FEDERAL AND STATE TAX TABLES
Table 1 - Federal Taxes
<TABLE>
<S> <S> <S> <S> <S>
Head of Married Married Marginal
Individual Joint Household
Single Return Return Tax Rate
0 to 0 to 0 to 0 to 15.0%
$31,250 $23,500 $19,500 $39,900
$31,250 to $23,500 to $19,500 to $39,900 to
28.0%
$80,750 $56,550 $47,125 $94,250
$80,750 to $56,550 to $47,125 to $94,2500 to
31.0%
$130,800 $117,950 $71,800 $143,600
$130,800 to $117,950 to $71,800 to $143,600 to
36.0%
$256,500 $256,500 $128,250 $256,500
$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.
C-6
<PAGE>
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-7
<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-8
<PAGE>
APPENDIX D TO THE PROSPECTUS
DUANE, MORRIS & HECKSCHER LLP
1667 K Street, NW, Suite 700
Washington, DC 20006
January 22, 1998
Petroleum Development Corporation
103 East Main Street
Bridgeport, West Virginia 26330
Re: PDC 2000 Drilling Program
Dear Sirs:
We have acted as counsel for PDC 2000 Drilling Program, in
connection with the offer and sale of securities (the "Units") in a series
of limited partnerships, PDC 1998-_ Limited Partnerships, PDC 1999-_
Limited Partnerships and PDC 2000-_ 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
Partnerships or the amount of each Investor Partner's share of allowable
losses or credits from the Partnerships' activities.
D-1
<PAGE>
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 Tax
Relief Act of 1997 enacted into law on August 5, 1997, 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.
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 or a publicly traded partnership.
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 1998, with respect to Partnerships
designated "PDC 1998-_ Limited Partnership", 1999 with respect to
Partnerships designated "PDC 1999-_ Limited Partnership", and 2000 with
respect to Partnerships designated "PDC 2000-_ Limited Partnership."
D-2
<PAGE>
4. The deductibility of losses generated from the Partnership
will not be limited by the at risk rates or f the limitations related to
an Investor's adjusted basis of the Partnership interest.
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 interests in 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 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.
D-3
<PAGE>
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.
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 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."
5. The Managing General Partner will cause the Partnership to
properly elect to deduct currently all Intangible Drilling and Development
Costs.
6. The Partnership will have a December 31 taxable year and will
report its income on the accrual basis.
7. 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, 1999 with respect to
Partnerships designated "PDC 1998-_ Limited Partnership", March 30, 2000
with respect to Partnerships designated "PDC 1999-_ Limited Partnership"
and 2001 with respect to Partnerships designated "PDC 1999-_ 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.
8. The Operating Agreement will be duly executed and will govern
the operation of the Partnership's Wells.
D-4<PAGE>
9. 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 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.
10. 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.
11. The Partnership will have the objective of carrying on
business for profit and dividing the gain therefrom.
12. 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
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.
D-5
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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. 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.
As discussed below, our opinion that the Partnership will not be
classified a corporation or as an association taxable as a corporation is
based in part on newly promulgated entity classification regulations and
in part on the fact that in our opinion the Partnership will not
constitute a "publicly traded partnership."
A. Association Taxable as a Corporation
Our opinion that the Partnership will not be treated as an
association taxable as a corporation is based on regulations issued by the
Internal Revenue Service on December 17, 1996, generally effective as of
January 1, 1997, regarding the tax classification of certain business
organizations (the "Check the Box Regulations").
Under the Check the Box Regulations, in general, a business entity
that is not otherwise required to be treated as a corporation under such
regulations will be classified as a partnership if it has two or more
members, unless the business entity elects to be treated as a corporation.
The Partnership is not required under the Check the Box Regulations to be
treated as a corporation and the Managing General Partner will not elect
that the Partnership be treated as a corporation. Accordingly, in our
opinion the Partnership will not be treated as an association taxable as
a corporation.
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 (the
substantial equivalent thereof). Code Section 7704(b). Regulation
Section 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.
D-6
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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 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 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.
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.
D-7
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C. Summary
Based on the above, management but should be, in our opinion the
Partnership will not be treated as an association taxable as a corporation
for federal income tax purposes by reason of the check the Box
Regulations. 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 not be treated as a corporation for
federal income tax purposes. Accordingly, the Partnership in our opinion
will be treated as a partnership for federal income tax purposes. 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.
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.
D-8
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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
$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.
D-9
<PAGE>
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
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.
D-10<PAGE>
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,
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, 1999 for Partnerships designated
"PDC 1998-_ Limited Partnership", March 30, 2000 for Partnerships
designated "PDC 1999-_ Limited Partnership" and March 30, 2001 for
Partnerships designated "PDC 2000-_ Limited Partnership" and will complete
each well, if completion is warranted, with due diligence thereafter.
Further, the 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).
D-11
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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.
Petroleum Development Corporation May 31, 1997 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 1998 for Partnerships designated "PDC 1998-_
Limited Partnership", 1999 for Partnerships designated "PDC 1999-_ Limited
Partnership" and 2000 for Partnerships designated "PDC 2000-_ Limited
Partnership"; however, the Managing General Partner has represented that
any Well that is not completed in 1998 with respect to Partnerships
designated "PDC 1998-_ Limited Partnership", in 1999 with respect to
Partnerships designated "PDC 1999-_ Limited Partnership" and in 2000 with
respect to the "PDC 2000-_ Limited Partnership" will be spudded by not
later than March 30, 1999 for Partnerships designated "PDC 1998-_ Limited
Partnership", March 30, 2000 for Partnerships designated "PDC 1999-_
Limited Partnership", and March 30, 2001 for Partnerships designated "PDC
2000-_ 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
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.
D-12<PAGE>
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
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.
D-13
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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, 1999 for Partnerships designated
"PDC 1998-_ Limited Partnership", March 30, 2000 for Partnerships
designated "PDC 1999-_ Limited Partnership" and March 30, 2001 for
Partnerships designated "PDC 2000-_ 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 its terms, we are of the opinion that the
payment for IDC under the Drilling and Operating Agreement, if made in
1998 for Partnerships designated "PDC 1998-_ Limited Partnership", 1999
for Partnerships designated "PDC 1999-_ Limited Partnership" and 2000 for
Partnerships designated "PDC 2000-_ Limited Partnerships," will be
allowable as a deduction in 1998 for Partnerships designated "PDC 1998-_
Limited, 1999 for Partnerships designated "PDC 1999-_ Limited Partnership"
and 2000 for Partnerships designated "PDC 2000-_ 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 1998 for Partnerships designated
"PDC 1998-_ Limited Partnership", 1999 for Partnerships designated "PDC
1999-_ Limited Partnership" and 2000 for Partnerships designated "PDC
2000-_ 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 1999 for Partnerships designated "PDC 1998-_ Limited
Partnership", 2000 for Partnerships designated "PDC 1999-_ Limited
Partnership", and 2001 for Partnerships designated "PDC 2000-_ Limited
Partnership" are not deductible in whole or in part until 1999, 2000 or
2001, respectively. Further, to the extent drilling of the Partnership's
wells does not commence by March 30, 1999 for Partnerships designated "PDC
1998-_ Limited Partnership", March 30, 2000 for Partnerships designated
"PDC 1999-_ Limited Partnership" and March 30, 2001 for Partnerships
designated "PDC 2000-_ 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. Treasury
regulations 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).
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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,
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, in general,
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). In the case of "stripper well
property", as that term is defined in Code Section 613A(c)(6)(D), the 100%
of taxable income limitation has been eliminated for taxable years 1998
and 1999. Code Section 613A(c)(6)(H). It is anticipated that the
properties of the Partnerships will likely constitute "stripper well
properties" for this purposes. 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.
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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.
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.
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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.
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.
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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.
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
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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).
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
limitations related to the adjusted basis rules will limit the
deductibility of losses generated from the Partnership.
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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.
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
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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
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
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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 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
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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 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
for such year. 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.
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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
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 holding of Rev.
Rul. 84-52 was confirmed in Rev. Rul. 95-37, 1995-1, C.B. 130. 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)
Petroleum Development Corporation pursuant to Treas. Reg. Section
1.708-1(b)(1)(ii) a transaction governed by Code Section 721 is not
D-24<PAGE>
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.
Based on the authority of If Rev. Rul. 84-52 and Rev. Rul. 95-37,
supra, is not overruled, revoked, or modified, the Partnership, in our
opinion, will not be terminated under Code Section 708 as a result of the
conversion of Partnership interests.
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
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
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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 Section 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). "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
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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 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 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.
D-27<PAGE>
Gain or loss recognized upon the disposition of property used in a
trade or business and held for more than 18 months 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 18 months, mid-term capital gain if held
more than one year but no more than 18 months, and short term capital gain
if held one year or less. 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
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 Section
751. 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).
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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.
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.
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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
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
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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).
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 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
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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. 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.
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 12.8% 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 "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.
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<PAGE>
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
account adjustments under the partnership agreement must be recognized
under the general allocation requirements of the regulations under Code
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.
D-33<PAGE>
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.
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" am bit 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).
D-34
<PAGE>
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
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 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.
D-35
<PAGE>
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).
Generally, 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, 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
D-36
<PAGE>
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
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.
D-37
<PAGE>
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 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
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.
D-38
<PAGE>
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/ DUANE, MORRIS & HECKSCHER LLP
<PAGE>
PART II. INFORMATION NOT REQUIRED IN PROSPECTUS
Item 14. Indemnification of Directors and Officers.
Registrant hereby incorporates herein by reference Section 6.04
"Indemnification of Managing General Partner" of the Limited Partnership
Agreement which is included as Appendix A to the Prospectus, which is
filed as a part of this Registration Statement.
Item 16. Exhibits and Financial Schedules.
(a) Exhibits.
(3)(a). Form of Limited Partnership Agreement (included as
Appendix A to the prospectus, which is filed as a
part of this Registration Statement).
(8). Opinion of Duane, Morris & Heckscher LLP as to
various tax matters discussed in the prospectus
(included as Appendix D to the prospectus, which is
filed as a part of this Registration Statement).
(23)(a). Consent of Duane, Morris & Heckscher LLP (included
in Part II of Registration Statement).
(23)(b). Consent of KPMG Peat Marwick LLP (included in Part
II of Registration Statement).
(23)(c). Consent of Wright & Company, Inc. (included in Part
II of Registration Statement).
(b) Financial Statement Schedules:
None.
(c) Financial Data Schedule:
None.
Item 17. Undertakings.
The undersigned registrant hereby undertakes:
(1) To file, during any period in which offers or sales are being
made, a post-effective amendment to this registration statement:
(i) To include any prospectus required by section 10(a(3) of
the Securities Act of 1933;
<PAGE>
(ii) To reflect in the prospectus any facts or events arising
after the effective date of the registration statement (or the most recent
post-effective amendment thereof) which, individually or in the aggregate,
represent a fundamental change in the information set forth in the
registration statement;
(iii) To include any material information with respect to the
plan of distribution not previously disclosed in the registration
statement or any material change to such information in the registration
statement;
(2) That, for the purpose of determining any liability under the
Securities Act of 1933, each such post-effective amendment shall be deemed
to be a new registration statement relating to the securities offered
therein, and the offering of such securities at that time shall be deemed
to be the initial bona fide offering thereof.
(3) To remove from registration by means of a post-effective
amendment any of the securities being registered which remain unsold at
the termination of the offering.
(4) The registrant will not identify to any third party any
prospects which will go into or are likely to be placed into the program,
or are representative of prospects which may be placed in the program,
whether such third party is a selling dealer or other party involved with
making or directing investment decisions regarding the purchase of program
interests, except to the extent such prospects have been identified in the
prospectus or an amendment thereto.
(5) To the extent a review of prospects or lease inventory is
permitted to third parties, it will be:
(a) only incidental to an underwriter's due diligence
examination;
(b) no reference to any specific property (unless such
property is described in the prospectus or an amendment) will appear in
any analysis or report on the program prepared by such third party; and
(c) any third party, prior to receiving permission to
examine properties will agree to the above conditions, and registrant will
file a copy of such agreement(s) as an exhibit to the registration
statement.
(6) No prospective investors or their representatives will be
permitted to examine any prospects or inventory or data related thereto
which is not described in the prospectus or an amendment thereto.
(7) An annual report on Form 10-K will be filed at the conclusion
of the fiscal year following the year in which the registration statement
is declared effective.
(8) A Form 8-K or final SR to reflect the expenditure of the
proceeds of the offering will be filed.
(9) Any revised prospectuses required by the provisions of Section
10(a)(3) of the Securities Act of 1933, as amended, will be filed as
post-effective amendments to the registration statement.
- 2 - <PAGE>
(10) For the purpose of determining any liability under said Act
(without thereby affecting the original effective date of this
registration statement for the purpose of Section 10(a)(3) of said Act)
each such post-effective amendment may be deemed to be a new registration
statement relating to the securities offered thereby, and the offering of
such securities at that time may be deemed to be the initial bona fide
offering thereof and that such post-effective amendment will comply with
the applicable forms and rules and regulations of the Commission in effect
at the time such post-effective amendment is filed.
(11) The prospectus will be supplemented at the close of any
partnership to state the number of participants in that partnership, the
amount of participation sold therein, the cumulative amount sold under all
partnerships formed under the subject registration statement, the amount
of interests to be offered in the next partnership and in succeeding
partnerships to be formed under this registration statement.
(12) The Registrant undertakes to send to each Investor Partner at
least on an annual basis a detailed statement of any transactions with the
Managing General Partner or its Affiliates, and of fees, commissions,
compensation, and other benefits paid, or accrued to the Managing General
Partner or its Affiliates for the fiscal year completed, showing the
amount paid or accrued to each recipient and the services performed.
(13) The Registrant undertakes to send to the Investor Partners,
within 45 days after the close of each quarterly fiscal period, the
information specified by the Form 10-Q, if such report is required to be
filed with the Commission.
(14) The Registrant undertakes to provide to the Investor Partners
the financial statements required by Form 10-K for the first full fiscal
year of operations of the Partnership.
(15) The undersigned Registrant hereby undertakes to provide to the
Underwriter at the closing specified in the underwriting agreements
certificates in such denominations and registered in such names as
required by the Underwriter to permit prompt deliver to each purchaser.
The registrant undertakes to file a sticker supplement pursuant to
Rule 424(c) under the Act during the distribution period describing each
property not identified in the prospectus at such time as there arises a
reasonable probability that such property will be acquired and to
consolidate all such stickers into a post-effective amendment filed at
least once every three months, with the information contained in such
amendment provided simultaneously to the existing Limited Partners. Each
sticker supplement should disclose all compensation and fees received by
the General Partner(s) and its affiliates in connection with any such
acquisition. The post-effective amendment shall include audited financial
statements meeting the requirements of Rule 3-05 of Regulation S-X only
for properties acquired during the distribution period.
3
<PAGE>
The registrant also undertakes to file, after the end of the
distribution period, a current report on Form 8-K containing the financial
statements and any additional information required by Rule 3-05 of
Regulation S-X, to reflect each commitment (i.e., the signing of a binding
purchase agreement) made after the end of the distribution period
involving the use of 10 percent or more (on a cumulative basis) of the net
proceeds of the offering and to provide the information contained in such
report to the Limited Partners at least once each quarter after the
distribution period of the offering has ended.
Insofar as indemnification for liability arising under the
Securities Act of 1933 may be permitted to directors, officers and
controlling persons of the Registrant pursuant to the foregoing
provisions, or otherwise, the Registrant has been advised that in the
opinion of the Securities and Exchange Commission such indemnification is
against public policy as expressed in the Act and is, therefore,
unenforceable. In the event that a claim for indemnification against such
liabilities (other than the payment by the Registrant of expenses incurred
or paid by a director, officer or controlling person of the Registrant in
the successful defense of any action, suit or proceeding) is asserted by
such director, officer or controlling person in connection with the
securities being registered, the Registrant will, unless in the opinion of
its counsel the matter has been settled by controlling precedent, submit
to a court of appropriate jurisdiction the question whether such
indemnification by it is against public policy as expressed in the Act and
will be governed by the final adjudication of such issue.
- 4 -
<PAGE>
CONFORMED COPY
SIGNATURES
Pursuant to the requirements of Securities Act of 1933, the
Registrant has duly caused this Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of
Bridgeport, State of West Virginia, on January 29 , 1998.
PDC 2000 Drilling Program
(Registrant)
By: Petroleum Development Corporation,
a Nevada corporation,
Managing General Partner
By /s/ Steven R. Williams
Steven R. Williams
Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed by the following persons in the
capacities and on the dates indicated:
Signature Title Date
/s/ James N. Ryan Chairman of the Board January 29, 1998
James N. Ryan (Principal Executive Officer)
/s/ Steven R. Williams President and Director January 29, 1998
Steven R. Williams
/s/ Dale G. Rettinger Executive Vice President, January 29, 1998
Dale G. Rettinger Treasurer and Director
(Principal Financial
Officer and Principal
Accounting Officer)
/s/ Roger J. Morgan Secretary and Director January 29, 1998
Roger J. Morgan
-5-
<PAGE>
The following index lists the Exhibits which are being filed in connection
with this Form S-1.
<PAGE>
EXHIBIT INDEX
NUMBER DESCRIPTION
PAGE
(23)(a). Consent of Duane, Morris & Heckscher LLP
(included in Part II of Registrant Statement).
(23)(b). Consent of KPMG Peat Marwick LLP (included in Part
II of Registration Statement).
(23)(c). Consent of Wright & Company, Inc. (included in Part II
of Registration Statement).
INDEPENDENT AUDITORS' CONSENT
The Board of Directors
Petroleum Development Corporation
We consent to the use of our report included herein and to
the reference to our firm under the heading "Experts" in the
prospectus.
/s/ KPMG Peat Marwick LLP
Pittsburgh, Pennsylvania
January 29, 1998
CONSENT OF INDEPENDENT PETROLEUM CONSULTANTS
We consent to the designation of our company in the
Prospectus portion of the Registration Statement under the
heading "Experts."
/s/ Wright & Company, Inc.
January 29, 1998
CONSENT OF COUNSEL
We consent to the designation of our firm in the Prospectus
portion of the Registration Statement under the heading "Legal
Opinions".
/s/ Duane Morris & Heckscher LLP
Duane Morris & Heckscher LLP
January 29, 1998
