As filed with the Securities and Exchange Commission on June 6, 2000
Registration No. 333-41977
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
POST-EFFECTIVE AMENDMENT NO. 3
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
$150 million offered ($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,
Colorado, Montana and other states.
THESE SECURITIES ARE SPECULATIVE AND INVOLVE A HIGH DEGREE OF RISK.
SEE "RISK FACTORS" on page 11. Investment risks and considerations
include:
- Drilling gas wells is highly risky; an investor might lose his
or her entire investment.
- No investor may participate in the management of any
partnership.
- The Program has not yet selected any prospects for gas
drilling; thus, no investor can evaluate any prospect before
investing.
- No market will develop for the Units; the investment is
illiquid; you may not be able to sell your Units.
- Investors may be subject to unlimited liability.
- Significant tax considerations are involved in an investment.
The Dealer Manager and selling brokers must sell the minimum of $1.5
million of Units in a limited partnership ($2.5 million with respect
to PDC 2000-D Limited Partnership) if any Units are sold. Units
beyond the minimum amount are being sold on a best efforts basis. The
offerings of partnerships designated PDC 2000- Limited Partnership
will terminate on December 29, 2000. Chase Manhattan Trust Company
will hold subscription proceeds of each Partnership in a separate escrow
account and will not release funds to a Partnership before the sale of the
minimum number of that Partnership's Units.
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED THE SECURITIES TO BE ISSUED BY THE
PROGRAM OR DETERMINED IF THIS PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY
REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
NEITHER THE ATTORNEY GENERAL OF THE STATE OF NEW YORK NOR THE ATTORNEY
GENERAL OF THE STATE OF NEW JERSEY NOR THE BUREAU OF SECURITIES OF THE
STATE OF NEW JERSEY HAS PASSED ON OR ENDORSED THE MERITS OF THIS OFFERING.
ANY REPRESENTATION TO THE CONTRARY IS UNLAWFUL.
<TABLE>
<C> <C> <C> <C> <C> <C>
Underwriting
Price to Discounts and Proceeds to the
Public Commissions Partnerships
Per Unit . . . $ 20,000 $ 2,100 (10.5%) $ 17,900 (89.5%)
Total Minimum. $ 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>
PDC Securities Incorporated, Dealer Manager
and an Affiliate of the Managing General Partner
The date of this Prospectus is , 2000.
TABLE OF CONTENTS
Page
SUMMARY........................................................... 1
RISK FACTORS.......................................................11
Special Risks of the Partnership.............................11
Risks Pertaining to Natural Gas Investments..................17
Tax Status and Tax Risks.....................................18
TERMS OF THE OFFERING..............................................21
General.......................................................24
Activation of Partnerships....................................25
Types of Units................................................26
Conversion of Units by Managing General Partner and
Additional General Partners..................................26
Unit Repurchase Program.......................................27
Investor Suitability..........................................29
ASSESSMENTS AND FINANCING..........................................32
SOURCE OF FUNDS AND USE OF PROCEEDS................................33
Source of Funds...............................................33
Use of Proceeds...............................................33
Subsequent Source of Funds....................................35
PARTICIPATION IN COSTS AND REVENUES................................35
Profits and Losses; Cash Distributions........................35
Revenues......................................................37
Costs.........................................................37
Allocations Among Investor Partners; Deficit Capital Account
Balances.....................................................40
Cash Distribution Policy......................................41
Termination...................................................42
Amendment of Partnership Allocation Provisions................42
COMPENSATION TO THE MANAGING GENERAL PARTNER AND AFFILIATES........42
PROPOSED ACTIVITIES................................................46
Introduction..................................................46
Drilling Policy...............................................48
Acquisition of Undeveloped Prospects..........................49
Title to Properties...........................................50
PDC Prospects.................................................51
Prospect Area Description.....................................51
Drilling and Completion Phase.................................58
Production Phase of Operations................................63
Interests of Parties..........................................64
Insurance.....................................................65
The Managing General Partner's Policy Regarding Roll-Up
Transactions.................................................66
COMPETITION, MARKETS AND REGULATION................................67
Competition and Markets.......................................67
Regulation....................................................69
Natural Gas Pricing...........................................69
Proposed Regulations..........................................70
MANAGEMENT.........................................................70
General Management............................................70
Experience and Capabilities as Driller/Operator...............70
Petroleum Development Corporation.............................71
Certain Shareholders of Petroleum Development Corporation.....73
Remuneration..................................................73
Legal Proceedings.............................................73
i
Page
CONFLICTS OF INTEREST..............................................74
Certain Transactions..........................................78
FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER...........80
PRIOR ACTIVITIES...................................................81
Prior Partnerships............................................81
Previous Drilling Activities..................................86
Payout and Net Cash Tables....................................89
Tax Deductions and Tax Credits of Partnerships in Previous
Partnerships................................................101
PARTNERSHIP PROVED RESERVES AND FUTURE NET REVENUES...............106
TAX CONSIDERATIONS................................................110
Summary of Conclusions.......................................110
General Tax Effects of Partnership Structure.................113
Intangible Drilling and Development Costs Deductions.........114
A. Classification of Costs.............................114
B. Timing of Deductions................................114
C. Recapture of IDC....................................115
Depletion Deductions.........................................115
Depreciation Deductions......................................116
Interest Deductions..........................................116
Transaction Fees.............................................116
Basis and At Risk Limitations................................117
Passive Loss Limitations.....................................118
A. Introduction........................................118
B. General Partner Interests...........................118
C. Limited Partner Interests...........................119
Conversion of Interests......................................119
Alternative Minimum Tax......................................119
Gain or Loss on Sale of Property or Units....................120
Partnership Distributions....................................121
Partnership Allocations......................................121
Profit Motive................................................122
Administrative Matters.......................................123
Accounting Methods and Periods...............................123
Social Security Benefits; Self-employment tax...............123
State and Local Taxes.......................................123
Individual Tax Advice Should Be Sought......................123
SUMMARY OF PARTNERSHIP AGREEMENT..................................123
Responsibility of Managing General Partner..................123
Liabilities of General Partners, Including Additional
General Partners...........................................124
Liability of Limited Partners...............................124
Allocations and Distributions...............................124
Voting Rights...............................................124
Retirement and Removal of the Managing General Partner......125
Term and Dissolution........................................125
Indemnification.............................................125
Reports to Partners.........................................127
Power of Attorney...........................................127
Other Provisions............................................127
ii
Page
TRANSFERABILITY OF UNITS..........................................127
PLAN OF DISTRIBUTION..............................................128
SALES LITERATURE..................................................130
LEGAL OPINIONS....................................................130
EXPERTS...........................................................130
ADDITIONAL INFORMATION............................................130
GLOSSARY OF TERMS.................................................131
FINANCIAL STATEMENTS..............................................F-1
APPENDICES:
A. Form of Limited Partnership Agreement.........................A-1
B. Subscription Agreement........................................B-1
C. Special Subscription Instructions.............................C-1
D. Opinion of Counsel -- Tax Considerations......................D-1
iii
SUMMARY
We qualify this summary in its entirety by the more detailed
information appearing elsewhere in this Prospectus. We direct prospective
investors to the "Glossary of Terms" (page 131 at the end of this
Prospectus, for definition of certain capitalized terms appearing
in throughout the Prospectus.
Terms of the Offering (page 21)
The Program. PDC 2000 Drilling Program (the "Program") is a series
of up to twelve limited partnerships (each referred to as a "Partnership"
or where the context so provides as the "Partnerships") to be formed under
the West Virginia Uniform Limited Partnership Act. The Program will sell
Units until December 29, 2000 with Units in the Partnerships
designated "PDC 2000-_ Limited Partnership" being offered only during
2000. A Limited Partnership Agreement (the "Partnership Agreement") will
govern the rights and obligations of the Partners of each Partnership. We
attach a form of the Partnership Agreement as Appendix A to the
Prospectus. For a description of the principal terms of the Partnership
Agreement, see "Summary of Partnership Agreement (page 123)." The
managing general partner of each Partnership will be Petroleum Development
Corporation (the "Managing General Partner"). The subscription periods
for all Partnerships designated "PDC 1999-_ Limited Partnership"
and designated "PDC 2000-_ Limited Partnership" will terminate on
December 29, 2000, unless earlier terminated by the Managing General
Partner. The offering of the Program's four 1998 limited partnerships,
PDC 1998-A through PDC 1998-D Partnership's, closed during 1998 with a
total of $40,877,452 of Units having been sold. The offering of the
Program's four 1999 limited partnerships, PDC 1999-A through PDC 1999-D
Partnership's, closed during 1999 with a total of $36,137,532.68 of Units
having have sold.
Units of Partnership Interest. The Program is offering for sales a
total of 7,500 Units at $20,000 per Unit, aggregating $150,000,000. The
program has already sold 4,098.59 units totalling $81,971,802. "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 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 and completion activities. Tax-exempt investors
and foreign investors may not purchase Units. The minimum investment by
an investor is $5,000.
Funding of a Partnership. 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 the PDC 2000-D Limited Partnership. The
maximum subscription for any Partnership is 750 units or
$15,000,000 ($25,000,0000 or 1,250 units for 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
- 1 -
sole discretion, provided that no offering of any Partnership designated
"PDC 2000-_ Limited Partnership" may extend beyond December
29, 2000. The Managing General Partner intends to terminate the
offering of each Partnership (assuming the sale of the minimum
subscription) at or near the time of the respective targeted closing dates
for each Partnership, which are set forth in "Terms of the Offering --
General (page 21)."
Subscription and Escrow. All subscriptions are payable in cash upon
subscription. The Managing General Partner has selected Chase Manhattan
Trust Company as escrow agent (the "Escrow Agent") to hold all
Subscription proceeds of each Partnership in a separate interest-bearing
escrow account. The execution and delivery of the Subscription Agreement
by a subscriber constitute a binding offer to buy Units in a Partnership.
Once an investor subscribes for Units, that investor may not revoke his or
her Subscription. The Escrow Agent will promptly return escrowed
Subscriptions to the respective subscribers of the particular Partnership
if the Partnership has not closed by the sixtieth day following the
anticipated offering termination date with respect to each respective
Partnership, PDC 2000-C Limited Partnership or PDC 2000-D Limited
Partnership has not closed on or before December 29, 2000,
respectively. In the event that the minimum required subscription of
$1,500,000 ($2,500,000 with respect to PDC 2000-D Limited
Partnership) is not realized in the offering of Units of any particular
Partnership, that Partnership will not close or receive funds from escrow,
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 on the subscription and without any
deduction from the subscriptions. For a full discussion of the
various terms of the offering, see "Terms of the Offering (page
21)."
Business of the Partnership. Each Partnership when formed will
drill, own, and operate natural gas wells in West Virginia, Michigan,
Pennsylvania, Colorado and/or Montana will produce and sell gas from these
wells. The Managing General Partner may determine that a Partnership will
drill wells in Utah, South Dakota, New York, Kentucky, Indiana, Kansas,
Ohio, Tennessee 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(page 46)" and "Glossary of Terms(page 131)" for
the definitions of "Development Well," "Exploratory Well," and other terms
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 and
completion operations of that Partnership. Moreover, Additional
General Partners (those investors who purchase Units of general
partnership interest) of a particular
-2-
Partnership will have the right to convert their Units into Units of
limited partnership interest and thereafter become limited partners of
that Partnership. See "Terms of the Offering -- Conversion of Units by
the Managing General Partner and by Additional General Partners(page
26)," "Proposed Activities -- Insurance (page 46) and "Tax
Considerations -- Conversion of Interests (page 110)."
Unit Repurchase Program. Beginning with the third anniversary of
the date of the first cash distribution of the particular Partnership,
Investor Partners (those persons who invest in a Partnership, either as
Additional General Partners or as Limited Partners) of that Partnership
may offer their Units to the Managing General Partner for repurchase.
Repurchase of Units is subject to certain conditions, including the
financial ability of the Managing General Partner to purchase the Units
and certain opinions of counsel. Subject to such financial condition and
opinions of counsel, the Managing General Partner will offer annually to
repurchase for cash a minimum of 10% of the Units originally subscribed to
in the Partnership. Subject to such conditions, the Managing General
Partner is obligated to purchase all Units presented to it by investors,
up to the 10% ceiling as stated above. The repurchase price will be based
upon a minimum of 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 (page
21)" and "Tax Considerations -- Conversion of Interests (page
27)."
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
(page 29)."
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, unlimited liability as an Additional
General Partner, lack of trading market in the units, and significant
tax considerations. See "Risk Factors" (page 11) and "Tax
Considerations (page 110)." 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 may take part in the
management or in the decision-making of the Partnership.
-3-
- The Managing General Partner will not select for acquisition
any Prospects for a Partnership until after activation of that
Partnership. Therefore, no investor will have an opportunity
to evaluate any Prospect 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 the
partnership 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 who wish to sell their Partnership interests may be
unable to do so, or may be able to sell them only for a price
less than a fair market value. There will be no market for
the Units.
- The Partnerships are subject to various conflicts of interest
arising out of their relationship with the Managing General
Partner. There can be no assurance that any transaction
between Managing General Partner and affiliated parties will
be on terms as 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 and
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 will be less diversification of the investors'
investment and less ability of the Partnership to spread the
risk of loss.
- 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.
- 4-
Risks Pertaining to Natural Gas Investments:
- Natural gas drilling is a highly speculative activity. There
is a possibility that wells drilled may not produce natural
gas. Even wells which are productive may not produce gas in
sufficient quantities to return all or a significant portion
of the investment.
- Future gas prices are unpredictable. If gas prices go down
investor returns will go down.
- Access to markets for gas produced by wells may be restricted
as a result of many factors, including distances to existing
pipelines, an oversupply of crude oil and natural gas,
changing demand from weather conditions, and regulations set
by federal and state governmental authorities. Such factors
may impede or delay revenues to the Partnerships.
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 on an Investor Partner's
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.
-5-
Compensation of the Managing General Partner (page 42)
The following is a tabular presentation of the items of compensation
with respect to 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 Competitive industry
Partner rates(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)
Affiliate Brokerage sales commissions; 10.5% of Subscriptions
reimbursement of due $157,500 ranging to
diligence and marketing $15.75 million(5)
support expenses; wholesaling
fees
</TABLE>
_____________________
(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 for sale of the minimum
number of Units to $375,000 for sale of the maximum number of Units
in a particular Partnership.
(3) Cannot be quantified until Partnership is conducting business.
See Page 63 for table of rates for various areas of
operations.
- 6 -
(4) Some of the gas produced by the Partnerships may be marketed by
Riley Natural Gas Company ("RNG"), 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 for sale of the maximum number of
Units ranging to $157,500 for sale of the minimum number of Units.
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 for sale of the minimum number of Units to $750,000 the
maximum number of Units.
Participation in Costs and Revenue (page 35)
Generally, Investor Partners will receive 80 percent and the
Managing General Partner will receive 20 percent of Partnership profits
and losses throughout the term of each Partnership; however, Investor
Partners may receive additional cash distributions if that Partnership
fails to meet the performance standard described below. If a particular
partnership does not fulfill the performance standard, that Partnership's
sharing arrangement will change 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 cash
distributions and estimated initial tax savings of 25% of investor
subscriptions, 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 (page 37). 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% RATE OF RETURN.
- 7 -
The table below summarizes the participation in the costs and
revenues of the Partnerships by the Managing General Partner and the
Investor Partners, taking account of the Managing General Partner's
contribution to the capital of the Partnerships. The table is
reproduced in full, with footnotes, under "Participation in Costs
and Revenues."
<TABLE>
<S> <S> <S>
Managing
Investor General
Partners(3) Partner (2)(3)
Partnership Costs
Broker-dealer Commissions and Expenses(1). . . 100% 0%
Management Fee . . . . . . . . . . . . . . . . 100% 0%
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. . . . . . . . . . . . . . . . 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%
____________________
(1) The Managing General Partner, and not the Partnership, will pay
Organization and Offering Costs, net of the Dealer Manager
commissions, discounts, due diligence expenses, and wholesaling
fees, of the Partnerships. In addition, the Managing General
Partner, without recourse to the Partnerships, will pay Organization
and Offering Costs, including commissions, in excess of 10 1/2% of
Subscriptions.
(2) To the extent that Investor Partners receive preferred cash
distributions (see "Participation in Costs and Revenues -- Revenues
- Revision to Sharing Arrangements"), the allocations for Investor
Partners will increase accordingly and the allocations for the
Managing General Partner will likewise decrease.
(3) As set forth in the following paragraph, the allocation of profits,
losses, and cash distributions of the Managing General Partner might
increase and the allocation of profits, losses, and cash
distributions, of the Investor Partners might decrease 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.
- 8 -
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,
discounts due diligence expenses, wholesaling fees, and the Management
Fee, will 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
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
increase to equal the percentage arrived at by dividing the Capital
Contribution made by the Managing General Partner by the Capital Available
for Investment, the allocation of the Investor Partners will decrease
accordingly.
</TABLE>
Application of Proceeds (page 33)
The Managing General Partner estimates that it will apply the
proceeds from the aggregate Capital Contributions of a Partnership as
follows, assuming the sale of the minimum number of Units. For a more
extensive presentation of the use of proceeds, see "Source of Funds and
Use of Proceeds" later in the Prospectus.
<TABLE>
<S> <S>
Activity Percentage of Total
Capital Contributions
Drilling and Completion Costs. . . . . . . . . . . . . . 89.3%
Organization and Offering Costs. . . . . . . . . . . . . 8.6%
Management Fee . . . . . . . . . . . . . . . . . . . . . 2.1%
Total. . . . . . . . . . . . . . . . . . . . . . . . . . 100.0%
</TABLE>
Tax Considerations; Opinion of Counsel (page 110)
Duane, Morris and Heckscher LLP has issued to the Managing General
Partner its opinion concerning all material federal income tax issues
applicable to an investment in the Partnerships. TO FULLY UNDERSTAND
THESE TAX ISSUES, EACH PROSPECTIVE INVESTOR PARTNER SHOULD READ THE TAX
OPINION IN APPENDIX D. 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 or 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 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 in general partnership interests will not be
considered a passive activity within the
- 9 -
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 in this
Prospectus, 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 (page 123)
The Partnership Agreement, which is attached to this Prospectus as
Appendix A, sets forth the rights of the Investor Partners. 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 may
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.
- 10 -
- The Managing General Partner will 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 will 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 may inspect the Partnership's books and records at
any reasonable time.
RISK FACTORS
Investment in the Partnerships involves a high degree of risk and is
suitable only for investors of substantial financial means who have no
need of liquidity in their investments. 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 their
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 (page 35)",
"Proposed Activities (page 46","Competition, Markets and
Regulations (page 67," and Tax Considerations (page 110),"
as well as those discussed elsewhere in this Prospectus. The Managing
General Partner cautions the reader, however, that this list of factors
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.
Special Risks of the Partnerships
DRILLING NATURAL GAS WELLS IS SPECULATIVE, MAY BE UNPROFITABLE, AND
MAY RESULT IN THE TOTAL LOSS OF ONE'S INVESTMENT. The drilling and
completion operations to be undertaken by each of the Partnerships for the
development of natural gas reserves are speculative and 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 (page 21)."
- 11 -
THE MANAGING GENERAL PARTNER WILL MANAGE EACH PARTNERSHIP, WITHOUT
ANY INVOLVEMENT BY ANY INVESTOR PARTNER. The Partnership Agreement
provides that the Managing General Partner will exclusively manage and
control all aspects of the business of each Partnership and will make all
decisions respecting the business of each Partnership. The Partnership
Agreement does not permit the Investor Partners to take part in the
management of any Partnership. See Article VI and Section 7.01 of the
Partnership Agreement attached as Appendix A.
THE MANAGING GENERAL PARTNER HAS NOT SELECTED ANY PROSPECTS FOR
ACQUISITION, AND AS A RESULT THE INVESTOR PARTNERS WILL BE UNABLE TO
EVALUATE ANY PROSPECTS BEFORE THEY INVEST IN THE PROGRAM. 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 OF A LENGTHY OFFERING PERIOD, DELAYS IN THE INVESTMENT OF AN
INVESTOR'S SUBSCRIPTION ARE LIKELY. Upon execution and delivery by the
investor, that investor's subscription will be irrevocable and cannot be
withdrawn. Because the offering period for a particular Partnership can
extend over a number of months and because the Managing General Partner
will acquire no Prospects until after activation of that Partnership,
delays in the investment of proceeds from the initial subscription date
are likely.
ADDITIONAL GENERAL PARTNERS WILL BE INDIVIDUALLY LIABLE FOR
PARTNERSHIP OBLIGATIONS AND LIABILITIES BEYOND THE AMOUNT OF THEIR
SUBSCRIPTIONS, PARTNERSHIP ASSETS, AND THE ASSETS OF THE MANAGING GENERAL
PARTNER. Under West Virginia law, the state in which each Partnership will
organize, 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 liable 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.
THE MANAGING GENERAL PARTNER AND ITS AFFILIATES WILL RECEIVE
COMPENSATION FROM THE PARTNERSHIP UPON FUNDING OF THE PARTNERSHIP AND
THROUGHOUT THE LIFE OF THE PARTNERSHIP. 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's share of operating profits in each Partnership will be 20%
(subject to revision). The Partnership at closing of the Partnership will
pay to the Managing General Partner a one-time Management Fee equal to
2.5% of total Subscriptions.
- 12 -
The Partnership will pay the Managing General Partner for drilling and
completing the Partnership's wells. The Partnership will pay the Managing
General Partner as operator for each producing well a monthly fee for
operations and field supervision, Partnership accounting, engineering,
management, and general and administrative expenses. 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 transactions with the
Partnership for services, supplies, and equipment and will be entitled to
compensation at competitive prices and terms. 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 for
sales commissions, reimbursement of bona fide due diligence expenses, and
wholesaling fees. See "Compensation to the Managing General Partner and
Affiliates (page 42)."
AN INVESTOR WHO SUBSCRIBES FOR UNITS CANNOT REVOKE THE
SUBSCRIPTION. The execution and delivery of the Subscription Agreement by
a subscriber constitute a binding offer to buy Units in a Partnership.
Once an investor subscribes for Units, that investor will not be able to
revoke the Subscription. Subscription proceeds of each Partnership will
be held in a separate interest-bearing escrow account with Chase Manhattan
Trust Company. In the event that the offering of Units in a particular
Partnership has not closed within the allotted offering period, the
Managing General Partner will cause the escrow agent to return promptly
all escrowed funds to the respective investors of that particular
Partnership with any interest earned on and without any deduction from
such funds.
THE PARTNERSHIP'S WELLS MIGHT NOT PRODUCE COMMERCIAL QUANTITIES OF
NATURAL GAS. The selection of Prospects for natural gas drilling is
inherently speculative and is subject to a high degree of risk. The
Managing General Partner cannot predict whether any Prospect will produce
natural gas or commercial quantities of natural gas. See "Proposed
Activities -- Acquisition of Undeveloped Prospects (page 49."
THERE WILL BE NO MARKET FOR THE UNITS; AND AS A RESULT AN INVESTOR
PARTNER MAY NOT BE ABLE TO SELL HIS OR HER UNITS. Investors may not be
able to sell their Partnership interests or may only be able to sell them
for less then a fair market value. There will be no market for the Units.
A sale or transfer of Units by an Investor Partner requires the prior
written consent of the Managing General Partner See "Transferability of
Units (page 127)."
SUFFICIENT INSURANCE COVERAGE MAY NOT BE AVAILABLE FOR THE
PARTNERSHIP, THEREBY INCREASING THE RISK OF LOSS FOR THE INVESTOR
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 case, the Managing General Partner may elect to change
the insurance coverage. Upon such change, Additional General Partners
could elect to become Limited Partners.
- 13 -
See "Proposed Activities -- Insurance (page 65)." 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 obligations and liabilities of the
Partnership. 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.
A PARTNERSHIP WHICH DRILLS FEWER WELLS WILL BE LESS DIVERSIFIED,
THEREBY INCREASING THE RISK OF FINANCIAL LOSS FOR THE 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 cost of drilling wells in different
geographic locations varies greatly. A Partnership subscribed at the
minimum level or which drills more expensive wells would be able to
participate in fewer Prospects, thereby decreasing the diversification of
the Partnership's investment in Prospects and increasing the risk of
financial loss to the Investor Partners.
THROUGH THEIR INVOLVEMENT IN PARTNERSHIPS AND OTHER NON-PARTNERSHIP
ACTIVITIES, THE MANAGING GENERAL PARTNER AND ITS AFFILIATES HAVE INTERESTS
WHICH CONFLICT WITH THOSE OF THE INVESTOR PARTNERS. 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. There can be no assurance that any transaction between the
Managing General Partner and affiliated parties will be on terms as
favorable as could have been negotiated with unaffiliated third parties.
See "Conflicts of Interest (page 77)."
THE PRODUCING LIFE AND PRODUCTIVITY OF PARTNERSHIP WELLS ARE
UNCERTAIN AND CANNOT BE PREDICTED. The Managing General Partner cannot
predict the life and production of any well. The actual lives could
differ from those anticipated. Partnership wells may not produce
sufficient gas for investors to receive a profit or even to recover their
initial investment.
UNAFFILIATED PERSONS MIGHT MANAGE JOINTLY-OWNED PARTNERSHIP
PROSPECTS; A PARTNERSHIP COULD BE FINANCIALLY LIABLE FOR OBLIGATIONS OF
SUCH JOINTLY-OWNED PROSPECTS. 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. As a result, 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 could 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 (page 58)."
- 14 -
A PARTNERSHIP MAY NOT BORROW FUNDS, EVEN IF NEEDED FOR PARTNERSHIP
OPERATIONS; AS A RESULT, THE PARTNERSHIP MIGHT NOT HAVE SUFFICIENT CAPITAL
FOR ITS OPERATIONS. 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
(page 35)" and "Proposed Activities -- Production Phase of
Operations -- Expenditure of Production Revenues (page 63)."
THE PARTNERSHIP AND OTHER PARTNERSHIPS SPONSORED BY THE MANAGING
GENERAL PROGRAM MAY COMPETE WITH EACH OTHER FOR PROSPECTS, EQUIPMENT,
CONTRACTORS AND PERSONNEL; AS A RESULT, THE PARTNERSHIP MIGHT FIND IT MORE
DIFFICULT TO OPERATE EFFECTIVELY. During 2000 and thereafter, the
Managing General Partner plans to offer interests in other partnerships to
be formed for substantially the same purposes as those of the
Partnerships. Therefore, a number of partnerships with unexpended capital
funds, including those partnerships to be formed before and after the
Partnerships, may exist at the same time. Due to competition among
partnerships for suitable Prospects and availability of equipment,
contractors, and Managing General Partner personnel, the fact that
partnerships previously organized by the Managing General Partner and its
Affiliates may still be purchasing Prospects (when the Partnership is
attempting to purchase Prospects) may make more difficult the completion
of Prospect acquisition activities by a Partnership.
THE PARTNERSHIP MAY DRILL EXPLORATORY WELLS, WHICH INVOLVES A
GREATER RISK OF FINANCIAL LOSS THAN DRILLING DEVELOPMENT WELLS. 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 Development Wells generally involves less
risk of Dry Holes but developmental acreage is more expensive and subject
to greater royalties and other burdens on production.
THE RESULTS OF DRILLING PREVIOUS PARTNERSHIPS SPONSORED THE MANAGING
GENERAL PARTNER ARE NOT INDICATIVE OF THE RESULTS TO BE EXPERIENCED BY THE
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 (page
48)," is not indicative of the results to be expected by these
Partnerships.
IN VIEW OF THE COST SHARING ARRANGEMENTS, THE INVESTOR PARTNER WILL
BEAR THE SUBSTANTIAL AMOUNT OF COSTS AND RISK OF NON-COMMERCIAL WELLS.
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.
- 15 -
INVESTOR PARTNERS MAY BE PERSONALLY LIABLE FOR ACTING CONTRARY TO
THE PARTNERSHIP AGREEMENT.The Investor Partners may not 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 the breach of the Partnership Agreement.
INDEMNIFICATION OF ADDITIONAL GENERAL PARTNERS BY MANAGING GENERAL
PARTNER COULD REDUCE THE VALUE OF THE PARTNERSHIP AND THE INVESTMENT
INTERESTS OF THE INVESTOR PARTNERS. The Managing General Partner has
agreed to indemnify each of the Additional General Partners for
obligations related to casualty and business losses which exceed available
insurance coverage and Partnership assets. Any successful claim of
indemnification will reduce the value of the Partnership. The value of
the investment interest of the Investor Partners would be reduced. In
such event, the Investor Partners could lose their entire investment in
the Partnership. The Managing General Partner will have no liability to
the Partnership or to any Investor Partner for any loss suffered by the
Partnership if the Managing General Partner in good faith determined that
its action was in the best interest of the Partnership and that such
action did not constitute negligence or misconduct of the Managing General
Partner. See "Summary of Partnership Agreement -- Indemnification (page
131)."
RECEIPT BY LIMITED PARTNERS OF PARTNERSHIP DISTRIBUTIONS COULD RESULT IN
LIABILITY OF SUCH LIMITED PARTNERS TO THE PARTNERSHIP. If Limited Partners
receive a return of any part of their Capital Contributions to a
Partnership, without violation of the Partnership Agreement or the West
Virginia Uniform Limited Partnership Act 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.
A SIGNIFICANT FINANCIAL LOSS BY THE MANAGING GENERAL PARTNER COULD
ADVERSELY AFFECT THE 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.
AN INVESTOR PARTNER MAY NOT RECEIVE A DISTRIBUTION IF THE
DISTRIBUTION WOULD CAUSE A 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.
THE DEALER MANAGER IS NOT INDEPENDENT AND HAS NOT CONDUCTED AN
INDEPENDENT DUE DILIGENCE EVALUATION OF THE OFFERING. 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 (page 74)."
- 16 -
Risks Pertaining to Natural Gas Investments
THE DRILLING OF GAS WELLS IS HIGHLY SPECULATIVE AND RISKY AND MAY
RESULT IN UNPROFITABLE WELLS. 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 completed wells 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
or restrict production or even make production impractical or impossible.
THE PRICES FOR NATURAL GAS HAVE BEEN QUITE UNSTABLE; A DECLINE IN
THE PRICE COULD ADVERSELY IMPACT THE PARTNERSHIP. Global economic
conditions, political conditions, and energy conservation have created
unstable prices. Revenues of each Partnership are directly related to
natural gas prices which the Managing General Partner cannot predict. 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.
FLUCTUATING MARKET CONDITIONS, INTENSE COMPETITION IN DRILLING, AND
GOVERNMENT REGULATIONS MAY ADVERSELY AFFECT THE PROFITABILITY OF THE
PARTNERSHIP. 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 occur in areas
of the United States. The effect of a surplus may be to reduce the price
the Partnerships receive for their gas production, or to reduce the amount
of natural gas that the Partnerships may produce and sell. As a result,
the Partnership may not be profitable. See "Competition, Markets and
Regulation (page 67)."
ENVIRONMENTAL HAZARDS INVOLVED IN DRILLING GAS WELLS MAY RESULT IN
SUBSTANTIAL LIABILITIES FOR THE PARTNERSHIP. 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 pay personal
injury and property damage claims and the costs of controlling blowouts or
replacing destroyed equipment rather than for drilling activities.
INCREASES IN DRILLING COSTS WOULD ADVERSELY AFFECT THE PARTNERSHIP'S
PROFITABILITY. The oil and gas industry historically has experienced
periods of rapid cost increases from time to time. Increases in the cost
of exploration and development would affect the ability of the
Partnerships to acquire additional Leases, gas equipment, and supplies and
would adversely affect the profitability of the Partnerships.
- 17 -
A REDUCED AVAILABILITY OF DRILLING RIGS MAY ADVERSELY AFFECT THE
OPERATIONS OF THE PARTNERSHIPS. 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 factors may reduce the availability of rigs to the
Partnership resulting in delays in drilling activities. The reduced
availability of rigs may adversely affect the operations of the
Partnerships.
FAILURE BY SUBCONTRACTORS TO PAY FOR MATERIALS OR SERVICES COULD
ADVERSELY AFFECT THE PARTNERSHIP'S PROFITABILITY. 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.
VARIOUS PRODUCTION AND MARKETING CONDITIONS MAY CAUSE DELAY IN
PARTNERSHIP GAS PRODUCTION AND ADVERSELY AFFECT THE PARTNERSHIP'S
PROFITABILITY. Drilling wells in areas remote from marketing facilities
may delay production from those wells until sufficient reserves are
established to justify construction of necessary pipelines and production
facilities. The Partnership's inability to complete wells in timely
fashion may also result in production delays. In addition, marketing
demands which tend to be seasonal may reduce or delay production from
wells. 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 or reduce sales from Partnership wells.
Tax Status and Tax Risks
It is possible that the tax treatment currently available with
respect to natural gas exploration and production will change on a
retroactive or prospective basis as a result of additional legislative,
judicial, or administrative actions. See "Tax Considerations (page
110)."
PARTNERSHIP CLASSIFICATION AS A PUBLICLY TRADED PARTNERSHIP WOULD
SUBSTANTIALLY ALTER THE TAX TREATMENT OF THE PARTNERSHIP. Tax counsel has
rendered its opinion that each Partnership will be classified for federal
income tax purposes as a partnership and not as a corporation, or an
association taxable as a corporation or as a "publicly traded partnership"
taxable as a corporation. Such opinion is not binding on the Service or
the courts. The Service could assert that a Partnership should be
classified as one of these other structures. 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 (page 113)."
- 18 -
SUBSTANTIALLY DIFFERENT TAX CONSIDERATIONS ARE INVOLVED IN ONE'S
CHOICE TO INVEST AS AN ADDITIONAL GENERAL PARTNER OR AS A LIMITED PARTNER.
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. A Limited Partner cannot
utilize any passive losses generated by the Partnerships until he or she
is in receipt of passive income.
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. After conversion of an Additional
General Partner's interest to that of a Limited Partner, 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."
UNDER THE CODE, A PARTNER'S TAX LIABILITIES MAY EXCEED THE CASH
DISTRIBUTIONS RECEIVED BY SUCH PARTNER. Federal income tax payable by an
Investor Partner by reason of his or her 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 or
her own return for a taxable year his or her 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 the income
is actually distributed.
IF THE SERVICE AUDITS THE PARTNERSHIP'S TAX RETURNS, AN INVESTOR
PARTNER MIGHT OWE MORE TAXES. 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
(page 122)."
PARTNERSHIP LOSSES AFTER THE CONVERSION OF GENERAL PARTNERSHIP
INTERESTS TO LIMITED PARTNERSHIP INTERESTS WILL BE PASSIVE LOSSES FOR TAX
PURPOSES. 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.
- 19 -
A MATERIAL PORTION OF THE SUBSCRIPTION PROCEEDS WILL NOT BE
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 (page 116)."
THE SERVICE COULD CHALLENGE THE PARTNERSHIP'S PREPAYMENT OF DRILLING
COSTS. Some drilling cost expenditures may be made as prepayments
during 2000 (with respect to Partnerships designated "PDC 2000-_
Limited Partnership"), for drilling and completion operations which in
large part may be performed during 2001. 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 29, 2000; 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 (page 114)."
COUNSEL'S TAX OPINION DOES NOT COVER VARIOUS TAX CONSIDERATIONS
INVOLVED IN ONE'S INVESTMENT IN THE PARTNERSHIP. Due to the lack of
authority, or the essentially factual nature of the question, 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 may vary from taxpayer to
taxpayer and may 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.
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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 Cost per Unit
- 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.
PDC 2000 Drilling Program (the "Program") will offer for sale an
aggregate of $150,000,000 of preformation interests in a series of up to
twelve limited partnerships to be formed in 7,500 Units of $20,000 per
Unit. Only prospective investors who meet the suitability standards set
forth below may purchase Units. The Program will offer Units for sale
over a three-year period with interests in the partnerships designated
"PDC 1998-_ Limited Partnership" being offered only during 1998 (already
completed), interests in the partnerships designated "PDC 1999-_ Limited
Partnership" (already completed) 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). The Program will not sell Units 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 and PDC 2000-D Limited Partnership) and
upon termination of the offering of Units in that Partnership, the
Managing General Partner will form a limited partnership under the laws of
West Virginia. At that time the units of preformation general partnership
interest and preformation limited partnership interest will become Units
of general partnership interest and Units of limited partnership interest,
respectively, in the particular Partnership. There is no restriction on
the composition of the type of partnership interests with respect to any
Partnership.
- 21 -
If the Managing General Partner does not sell the minimum required
aggregate subscription amount of $1,500,000 (or $2,500,000, as
appropriate) in the offering of Units of any Partnership, the Managing
General Partner will not fund that Partnership, 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 on the
escrow funds and without any deduction from the escrowed funds.
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 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, each of which has been organized and is currently
conducting business operations, 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 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" terminated on December 31, 1998, the Subscription
period for all Partnerships designated "PDC 1999-_ Limited Partnership"
terminated on December 31, 1999, and the Subscription period for
all Partnerships designated "PDC 2000-_ Limited Partnership" will
terminate on December 29, 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 2000-B Limited Partnership, PDC 2000-C Limited
Partnership, and PDC 2000-D Limited Partnership will terminate September
13, 2000, November 15, 2000, and December 29, 2000. The offering period
for PDC 2000-A terminated on May 22, 2000.The offering of any
particular Partnership may extend beyond its anticipated termination date
by not more than sixty days or be terminated earlier; however, no offering
of Partnerships designated "PDC 2000-_ Limited Partnership" may
extend beyond December 29, 2000. Except as otherwise stated below,
the offering of Units in subsequent Partnerships PDC 2000-A Limited
Partnership, PDC 2000-B Limited Partnership, PDC 2000-C Limited
Partnership or PDC 2000-D Limited Partnership as appropriate) will
not commence until the Subscription of Units in prior Partnerships
( PDC 2000-A Limited Partnership, PDC 2000-B Limited Partnership,
or PDC 2000-C Limited Partnership or PDC 2000-D Limited Partnership as
appropriate) has reached the minimum subscription or that prior
offering has terminated. The Managing General Partner may choose to offer
the Units of PDC 2000-C Limited Partnership and PDC 2000-D Limited
Partnership at the same time until the offering of Units in PDC
-22-
<PAGE>
2000-C Limited Partnership has 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
closed, the Managing General Partner will offer or sell no additional
Units with respect to that Partnership. At or about the time of funding
of a particular Partnership, it is anticipated that the Managing General
Partner will supplement this Prospectus to reflect the results of the
offering of such Partnership. No operations by a particular Partnership
will commence until termination of its offering period.
The Managing General Partner will fund each Partnership promptly
following the termination of its respective offering period, provided that
such Partnership has reached the minimum Subscriptions, 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 29, 2000, with respect
to Partnerships designated "PDC 2000-_ Limited Partnership,". The
Managing General Partner will not offer or sell any Units in a Partnership
after the close of its offering period and its funding.
Subscriptions for Units are payable $20,000 in cash per Unit
purchased upon subscription. The Managing General Partner will place all
Subscription proceeds of each Partnership in a separate interest-bearing
escrow account at Chase Manhattan Trust Company located at Oxford Centre,
Suite 1100, 301 Grant Street, Pittsburgh, Pennsylvania 15219 (the "Escrow
Agent"), during the offering period of such Partnership. The escrow
agreement requires the Escrow Agent to invest escrowed funds upon receipt
and forbids the Escrow Agent from disbursing 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 Managing General Partner fails to
raise the minimum subscriptions 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,"
the Escrow Agent will promptly return escrowed Subscriptions of
Partnerships not closed by the sixtieth day following the anticipated
offering termination date to the respective investor of that Partnership.
If the offering of Units in PDC 2000-C Limited Partnership or PDC
2000-D Limited Partnership has not closed on or before December 29,
2000, the Escrow Agent will promptly return the escrowed funds of that
particular Partnership to those investors. The Escrow Agent will not
commingle Subscriptions with the funds of the Managing General Partner or
its Affiliates, nor will Subscriptions be subject to the claims of their
creditors. The Escrow Agent will invest Subscription proceeds 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. 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. Investors should make their
checks for Units payable to "Chase as Escrow Agent for PDC 2000-_
Limited Partnership," and give their checks to their broker for
submission to the Dealer Manager and Escrow Agent.
-23-
An Investor's execution of the Subscription Agreement and its
acceptance by the Managing General Partner constitute the execution of the
Partnership Agreement and an agreement to be bound by the terms of the
Partnership Agreement 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 execute 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 receive funds following termination of
offering period.
- Each Partnership is a separate business and economic entity
from each other Partnership.
- Partnerships will organize under West Virginia law.
Each Partnership will organize under the Act and will receive funds
promptly following the termination of its offering period. However, a
Partnership will not be funded with less than the requisite minimum
aggregate Subscriptions. A Partnership will not have any substantial
assets or liabilities and will not commence any drilling operations until
after it is funded.
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 invest and will have no 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 the property of the respective Partnership
whose funds earned the interest.
The Managing General Partner anticipates that within 12 months
following the formation of a Partnership it will have expended or
committed all Subscriptions for Partnership operations. The Managing
General Partner will return any unexpended and/or uncommitted
Subscriptions at the end of such 12-month period 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" will not include
amounts set aside for necessary operating capital reserves.
The Managing General Partner will file a Certificate of Limited
Partnership and any other documents required to form the Partnerships with
the State of West Virginia and will elect for the Partnerships to be
governed by the West Virginia Uniform Limited Partnership Act. The
Managing General Partner will also take all other actions necessary to
qualify the Partnerships to do business as limited partnerships or cause
the limited partnership status of the Partnerships to be recognized in any
other jurisdiction where the Partnerships conduct business.
-24-
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 Investor Partners
will generally share income, gains, losses, deductions, and cash
distributions allocable to them 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 generally may offset Partnership losses and
deductions against income from any source. Limited Partners generally
may offset Partnership losses and deductions only against passive income.
Investors may transfer or assign their Units of partnership
interest in accordance with Section 7.03 of the Partnership Agreement.
Transferees seeking to become substituted Partners must 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 the admission of a Limited Partner to the
Partnership and each investor who purchases Units of limited partnership
interest being offered hereby. The liability of a Limited Partner of the
Partnership for the Partnership's debts and obligations will not exceed
that Partner's Capital Contributions, his or her share of Partnership
assets, and the return of any part of his or her Capital Contribution (a)
for a period of one year thereafter for the amount of his or her returned
contribution (if a Limited Partner has received the return 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 in violation of the Partnership Agreement or the
Act.
- 25 -
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 in this Prospectus 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 after drilling and completion operations have been
finished.
- 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 when drilling and completion operations of that
Partnership have been finished. 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
-26
<PAGE>
termination of the Partnership for tax purposes. A conversion made in
response to a material change in that Partnership's insurance coverage
will be effective prior to the effective date of the change in insurance
coverage. After the conversion of a partner's general partnership
interest to that of a Limited Partner, each converting Additional General
Partner will continue to have unlimited liability regarding Partnership
liabilities arising prior to the effective date of such conversion, but
will have limited liability to the same extent as Limited Partners after
conversion to Limited Partner status is effected.
The Managing General Partner is not entitled to convert its
interests into limited partnership interests. Limited Partners do not
have any right to convert their Units into Units of general partnership
interest. In the event Additional General Partners desire to convert to
Limited Partners due to a loss of insurance coverage and such conversions
would be permitted because they 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
agreements 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 the
counsel's opinion.
-27-
The Managing General Partner will not favor one particular
Partnership over another in the repurchase of Units. The Managing General
Partner will extend such offer equally to all interest holders
participating in an individual Partnership, excluding interests held by
the Managing General Partner. Notwithstanding the preceding sentence, if
Investor Partners tender more than 10% of the Units from a Partnership or
more Units than the Managing General Partner is able to purchase, the
Managing General Partner will purchase Units 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 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, the Managing General Partner will repurchase those particular
Units 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 must provide the Managing General Partner written notification of
such Partner's intention to have the Managing General Partner purchase his
or her 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 or she elects to accept the repurchase price, needs to 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.
An offering price established by the Managing General Partner may
not 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. Nevertheless, each Investor Partner is free to
accept or not to accept the offer 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 or her interest, based on the most
recent reserve evaluation prepared by an independent expert in accordance
-28-
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 1,133 units (out of approximately
6,098 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 6,098 units includes all partnerships through
and including PDC 1996-D 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
1996.
Investor Suitability
- Investment in the Units involves a high degree of risk.
- Only qualified investors may purchase Units.
- Investment is suitable only for investors having substantial
financial resources who understand the long-term nature, tax
consequences, and risk factors associated with this
investment.
- Minimum requirements are $225,000 net worth, or a net worth of
$60,000 and taxable income of $60,000.
- States with more stringent requirements are set forth below.
- Transferees of Units must meet the suitability requirements
set forth herein.
It is the obligation of persons selling Units to make every
reasonable effort to assure that the Units are suitable for investors,
based on the investor's investment objectives and financial situation,
regardless of the investor's income or net worth.
Units, including fractional Units, will be sold only to investors
who have a minimum net worth of $225,000 or a minimum net worth of $60,000
and had during the last tax year or estimate that they 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
will be determined exclusive of home, home furnishings and automobiles.
In addition, Units will be sold only to investors who make a written
representation that they are the sole and true party in interest and they
are 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.
-29-
Michigan, New Mexico, Ohio, 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
yearly 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. In addition, an Alaska
resident must have either: (i) a minimum annual gross income of $60,000
and a minimum net worth of $60,000, exclusive of principal automobile,
principal residence, and home furnishings, or (ii) a minimum net worth of
$225,000, exclusive of principal automobile, principal residence, and home
furnishings.
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), and $50,000 in taxable 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 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 $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.
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; 1999 for the PDC 2000 designated
Partnerships) taxable income of $60,000 or more, or estimates that his or
her 1998 (for the PDC 1998 designated Partnerships; 1999 for the PDC 1999
-30-
designated Partnerships; 2000 for the PDC 2000 designated Partnerships)
taxable income, as defined in Section 63 of the Code, will be $60,000 or
more, without regard to the investment in the Program; or (iii) that he or
she is purchasing in a fiduciary capacity for a person or entity who
satisfies the requirements of (i) or (ii).
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, Vermont or Washington who subscribes for
Units of general partnership interest must represent that he or she (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, New Mexico, Ohio,
Oklahoma, Oregon, Vermont and Washington must represent that he or she 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 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 in 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.
A resident of South Dakota 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 each of the current year and the
succeeding year.
-31-
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 may not borrow funds on behalf of the
Partnership or for Partnership activities.
- Operations for drilling wells by the particular Partnerships
will be funded through Subscription proceeds and capital
contributed to the Partnerships by the Managing General
Partner. Over the term of a Partnership, additional funds
might be 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) The Managing General Partner will prepare an AFE ("authority
for expenditures") estimate for the Partnership. The Operator
will complete the development work and will bill the
Partnership for the work performed; or
(b) The Managing General Partner will prepare an AFE estimate for
the Partnership. The Partnership will retain revenues from
operations until it has accumulated sufficient funds to pay
for the development work, at which time the Operator will
commence the work, and the Managing General Partner will pay
the Operator as the work progresses.
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.
-32-
The Partnership Agreement does not permit the Partnership 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." (page 115)
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; $2,000,000 ranging to $20,000,000 for PDC 1999-D
Limited Partnership and PDC 2000-D Limited Partnership) 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 for sale of 75 Units ranging
to $18,262,500 for sale of 7,500 Units.
Use of Proceeds
The program is offering for sale a total of 7,500 Units to fund up
to twelve Partnerships over a three-year period. In order to fund any
particular Partnership, the Program must sell a minimum of 75 Units
($1,500,000) with respect to that Partnership (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). The following table
presents information regarding the financing of a Partnership in four
different circumstances: (1) the sale of 750 Units ($15,000,000), the
maximum number of Units for any Partnership, designated as PDC 1998 [1999
or 2000] -A, -B, or -C Limited Partnership (2) the sale of 75 Units
($1,500,000),the minimum for any Partnership designated as PDC 1998 [1999
or 2000] -A, -B, or -C Limited Partnership, (3) the sale of 1,250 units
($25,000,000), the maximum for any -D designated Partnerships, and (4) the
sale of 125 units ($2,500,000), the minimum for any -D designated
Partnership. The Managing General Partner will disburse substantially
all of the funds available to the Partnership for the following purposes
and in the following manner:
-33-
<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%
____________________
(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 as 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 of 125
Units ($2,500,000).
-34-
(4) PDC Securities Incorporated, an Affiliate of the Managing General
Partner, may reallow in whole or in part up to $1,500,000 for the sale
of 750 Units are sold; (a maximum of $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 for the sale of the minimum
number of Units is sold; (a minimum of $250,000 for each of PDC 1998-D
Limited Partnership, PDC 1999-D Limited Partnership and 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
for the sale of 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 for the sale of the maximum number of Units ($125,000 for
each of PDC 1998-D Limited Partnership, PDC 1999-D Limited
Partnership, and PDC 2000-D Limited Partnership). Such payments will
be made in cash solely on the amount of initial Subscriptions.
(5) The Managing General Partner will pay Organization and Offering Costs
in excess of 10 1/2% of Subscriptions, without recourse to the
Partnership.
(6) Included in this amount is the Cost to the Partnerships of acquiring
Prospects, which may include Prospects acquired from the Managing
General Partner.
</TABLE>
Subsequent Source of Funds
As indicated above, the Managing General Partner will commit or expend
substantially all of the Partnership's initial capital following the
offering. The Partnership Agreement does not permit the Partnership to
borrow any funds for its activities. Consequently, Partnership production
must satisfy any future requirements for additional capital. See "Risk
Factors -- Shortage of Working Capital."
PARTICIPATION IN COSTS AND REVENUES
Profits and Losses; Cash Distributions
The Partnership's Agreement provides for the allocation of profits
and losses during the production phase of a particular Partnership and for
the distribution of cash available for distribution 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%
____________________
-35-
(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
Arrangements", 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 increase
to equal its percentage investment, and the investor partners' share
will correspondingly decrease. See "Cost -- Lease Costs, Tangible
Well Costs, and Gathering Line Costs" below.
</TABLE>
Revision to Sharing Arrangements. The Partnership Agreement provides
for the allocation of Partnership profits and losses 80% to the Investor
Partners and 20% to the Managing General Partner throughout the term of each
Partnership. However, the Partnership Agreement provides for the
enhancement of investor cash distributions if the particular Partnership
does not meet the performance standard described below during the ten-year
period commencing six months after the close 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 increase by ten
percentage points above the initial sharing arrangements for Investor
Partners and the allocation rate with respect to such items for the Managing
General Partner will decrease by ten percentage points below the initial
sharing arrangements for the Managing General Partner, until the Average
Annual Rate of Return increases to 12.8% or more, or until ten years and
six months from the closing date of the Partnership expire, whichever event
shall occur sooner. Average Annual Rate of Return for purposes of this
preferred sharing arrangement means (1) the sum of the cash distributions
and estimated initial tax savings of 25 percent of investor subscriptions,
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 change 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 NO INVESTOR PARTNER SHOULD CONSIDER THE POLICY 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 PERCENT RATE OF RETURN.
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.
-36-
Revenues
Natural Gas Revenues; Sales Proceeds. The Partnership Agreement
provides for the allocation of revenues from natural gas production and gain
or loss from the sale or other disposition of productive wells and Leases
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 above, and to revisions due to increases in the
Managing General Partners's Capital Contribution to cover tangible drilling
and Lease Costs.
Interest Income. The Program will credit to the Investor Partners
100% of any interest earned on the deposit of Subscription funds prior to
the closing of the offering and funding of the respective Partnership. The
Program will allocate and credit interest earned on the deposit of operating
revenues and revenues from any other sources 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. The Program will allocate to the Managing General
Partner 100% of all revenues from sales of equipment.
Costs
Organization and Offering Costs. The Managing General Partner, and
not the Partnership, will pay Organization and Offering Costs, net of the
Dealer Manager commissions, discounts and due diligence expenses, and
wholesaling fees, of the Partnerships. 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,
the Program will allocate and charge to the Managing General Partner 100%
of Organization and Offering Costs in excess of 10 1/2% of Subscriptions.
Management Fee. The Program will allocate the nonrecurring Management
Fee 100% to the Investor Partners and 0% to the Managing General Partner.
Lease Costs, Tangible Well Costs, and Gathering Line Costs. The
Program will allocate the Costs of Leases, tangible Well Costs and gathering
line Costs 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 Drilling and Completion, 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
increase its Capital Contribution. If the Managing General Partner's
Capital Contribution exceeds 21-3/4% of Subscriptions, the Managing General
Partner's share of all items of profit and loss during the production phase
of operations and cash available for distribution will be modified to
equal for the Managing General Partner the percentage arrived at
dividing the Capital Contributions of the Managing General Partner by the
Capital Available for Investment. The Investor Partners' allocations of
such items are changed accordingly.
Intangible Drilling Costs. The Program will allocate Intangible
Drilling Costs and recapture of Intangible Drilling Costs in proportion to
the Investor Partners' and Managing General Partner's respective payment of
Intangible Drilling Costs. Recapture, if any, attributable to intangible
drilling and development costs will be allocable on the same percentage
basis as the allocation of intangible drilling and development costs.
-37-
Investor Partners' portion of capital available for investment will
pay the 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 for Intangible Drilling Costs and
recapture of Intangible Drilling Costs will, be in proportion to the
Investor Partners' and the Managing General Partners and respective payment
of intangible drilling costs.
Operating Costs. The Program will allocate and charge Operating Costs
of Partnership wells 80% to the Investor Partners and 20% to the Managing
General Partner.
Direct Costs. The Program will allocate and change Direct Costs of
the Partnerships 80% to the Investor Partners and 20% to the Managing
General Partner.
Administrative Costs. The Program will allocate 100% of
Administrative Costs of the Partnerships 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 to this Prospectus.
<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%
</TABLE>
(1) The Managing General Partner, not the Partnership, will pay
Organization and Offering Costs, net of the Dealer Manager
commissions, discounts, due diligence expenses, and wholesaling fees,
of the Partnerships. In addition, the Managing General Partner,
without recourse to the Partnership, will pay Organization and
Offering Costs in excess of 10 1/2% of Subscriptions.
-38-
(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, Tangible Well Costs,
Gathering Line Costs; and Intangible Drilling 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 Program will allocate and credit to the
Partners the gain from such sale or disposition 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; the program will allocate
these revenues to the Investor Partners and the Managing General
Partner in the same percentages as allocation of oil and gas revenues.
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 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.
-39-
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
1997 1998 1999
Partnership % of % of % of
Name Amount Subscrip- Amount Subscrip- Amount Subscrip-
tions tions tions
PDC 1997-A 12,930 0.31% 9,244 0.22% 5,565 0.13%
PDC 1997-B 18,466 0.27% 10,139 0.15% 6,261 0.09%
PDC 1997-C 18,198 0.30% 10,243 0.17% 7,361 0.12%
PDC 1997-D 21,776 0.12% 23,412 0.13% 22,919 0.12%
PDC 1998-A -- -- 11,304 0.21% 9,287 0.18%
PDC 1998-B -- -- 14,921 0.21% 8,817 0.12%
PDC 1998-C -- -- 14,990 0.19% 9,518 0.12%
PDC 1998-D -- -- 17,780 0.09% 23,261 0.11%
PDC 1999-A -- -- -- -- 12,351 0.26%
PDC 1999-B -- -- -- -- 12,995 0.23%
PDC 1999-C -- -- -- -- 9,617 0.14%
PDC 1999-D -- -- -- -- 15,123 0.08%
Administrative Costs
1997 1998 1999
Partnership % of % of % of
Name Amount Subscrip- Amount Subscrip- AmountSubscrip-
tions tions tions
PDC 1997-A 0 0.00% 0 0.00% 0 0.00%
PDC 1997-B 0 0.00% 0 0.00% 0 0.00%
PDC 1997-C 0 0.00% 0 0.00% 0 0.00%
PDC 1997-D 0 0.00% 0 0.00% 0 0.00%
PDC 1998-A - - 0 0.00% 0 0.00%
PDC 1998-B - - 0 0.00% 0 0.00%
PDC 1998-C - - 0 0.00% 0 0.00%
PDC 1998-D - - 0 0.00% 0 0.00%
PDC 1999-A - - - - 0 0.00%
PDC 1999-B - - - - 0 0.00%
PDC 1999-C - - - - 0 0.00%
PDC 1999-D - - - - 0 0.00%
___________________
</TABLE>
Allocations Among Investor Partners; Deficit Capital Account Balances
The Program will allocate revenues and costs of a Partnership
allocated to the Investor Partners among them to 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, there will be no allocation of losses 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).
-40-
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.
- The Program will make cash distributions of 80% to the Investor
Partners and 20% to the Managing General Partner throughout the
term of the Partnership; cash distributions 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 Program cannot presently predict amounts of cash
distributions from the Program.
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 > 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, the Program will divide cash distributions 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. THE ABOVE-REFERENCED
REVISED SHARING ARRANGEMENT POLICY IS NOT, AND NO INVESTOR PARTNER SHOULD
CONSIDER THE POLICY 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.
-41-
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 Program
will distribute the assets of the Partnership to the Partners based upon
their Capital Account balances. If the Managing General Partner has a
deficit in its Capital Account, it must restore such deficit; however, no
Investor Partner will be obligated to restore his or her deficit, if any.
Amendment of Partnership Allocation Provisions
- The Managing General Partner may 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 must 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 Cost, or fair market
Partner rates value if materially
less than Cost(3)
Managing General Operator's Per-Well Cost, or fair market
Partner Charges value if materially
less than Cost(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)
-42-
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
_____________________
(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. See table on page 63 for
various area rates.
(4) Some of the gas produced by the Partnership may be marketed by Riley
Natural Gas Company ("RNG"), 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 for sale of the maximum number of
Units. ranging to $157,500 for sale of the minimum number of Units.
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 for sale of the maximum number
of Units to $7,500 for sale of the minimum number of Units.
</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 for sale of the
minimum number of Units ranging to $3,750,000 for sale of the maximum number
of Units. Since the Program can sell a maximum of $15 million ($25 million
with respect to each of PDC 1998-D Limited Partnership, PDC 1999-D Limited
Partnership and PDC 2000-D Limited Partnership) of Units 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).
-43-
The Partnership will reimburse the Managing General Partner 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 drill,
complete, and operate wells on such prospect. The Managing General Partner
may use its own personnel and equipment during the drilling and completion
phase of operations. The Managing General Partner will bill these services
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 70-80 wells annually 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 based upon the depth of the
well at its deepest penetration and whether the well is completed or plugged
as a dry hole. Different footage rates are established for each area of
operations based on drilling and completion costs for that area. A
lower rate is charged for wells which the Managing General Partner elects
to plug without attempting a completion. See "Proposed Activities, Drilling
Activities and Completion Phase, Drilling and Operating Agreement"(page 58).
In addition, in each area where the Partnership conducts its drilling
activities, 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.
-44-
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 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 LLP in their 1998-1999 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
$4,875 per well per month for wells in the Appalachian Basin; $7,500 per
well per month for wells up to 5,000 feet in the Michigan Basin; $6,514 per
well per month for wells in Colorado; and $3,663 per well per month for
wells up to 5,000 feet and $5,326 per well per month for wells 5,000 feet
to 10,000 feet in depth in Utah. 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 to other geologic zones, the Program will supplement
the prospectus 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
for each producing well a monthly fee based upon competitive industry rates
for operations and field supervision and $75 for Partnership accounting,
engineering, management, and general and administrative expenses. The
Operator will bill non-routine operations to the Partnership at their Cost.
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 RNG, its subsidiary. See
"Conflicts of Interest."
-45-
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
for sale of the maximum number of Units ranging to $157,500 for sale of the
minimum number of Units. PDC Securities Incorporated may, as Dealer
Manager, reallow such sales commissions and due diligence and marketing
support expenses in whole or in part to NASD licensed broker-dealers for
sale of the Units, reimbursement of due diligence and marketing support
expenses, and other compensation, but will retain the wholesaling fees of
$7,500 ranging to $750,000.
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 drill, complete, own and operate natural gas
wells. Partnership operations may include wells in West Virginia, Michigan,
Pennsylvania and Colorado as described in this prospectus. The
Managing General Partner may also conduct Partnership operations in other
formations not described in the prospectus in the previously listed states,
or in New York, Utah, South Dakota, Kentucky, Tennessee, Indiana, Kansas,
Wyoming North Dakota, Nebraska and/or Oklahoma, as it may deem
advisable. The Partnerships intend to apply at least 90% of the Capital
Contributions available for participation in drilling and completion
activities to comparatively lower risk Development Wells but may apply some
of the remaining 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. The cost of drilling wells in different
-46-
<PAGE>
wells in different geographic locations will vary greatly. If the Managing
General Partner drills more expensive wells, the partnership will be able
to drill fewer wells. As a result, the Partnership will be less able to
diversify its investment, and the risk associated with drilling will
increase. The number of wells drilled by a partnership is determined by the
amount of funds raised for the partnership and the specific prospects
drilled by that partnership, and cannot be determined in advance of the
closing of a partnership.
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 initial tax savings and monthly
cash distributions to the Investor Partners.
(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.
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.
-47-
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
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.
-48-
Acquisition of Undeveloped Prospects
- The Managing General Partner will select undeveloped Prospects.
- Selection of Prospects for a Partnership will occur after that
Partnership has been funded.
- At least 90% of Prospects will be development wells.
- The Partnerships will acquire Prospects at the lesser of Cost
or fair market value.
- Average royalty and overriding royalty burden will not exceed
20%.
- 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, Michigan to
develop the Antrim Formation and in Colorado to develop
Cretaceous Sandstones. The Managing General Partner reserves the right to
conduct Partnership operations in New York, Ohio, Utah, Montana,
South Dakota, Tennessee Kentucky, Indiana, Kansas, Wyoming, North Dakota,
Nebraska, Ohio 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.
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 all the subject wells. There
could also be some oil and brine production.
-49-
The Partnership will acquire Prospects under arrangements 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 20%. In its discretion the Managing General
Partner may acquire less than 100% of the Working Interest in a prospect
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 the Managing General Partner will assign to the
Partnerships a substantial portion of the Leases to be developed by the
Partnerships, the Partnerships may also purchase Leases directly from
unaffiliated persons. The Managing General Partner will transfer at its
cost all Leases which are transferred to the Partnerships, 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
- The Partnership will hold record title to Leases in its name.
Prior to the drilling of any Partnership well, the Managing General
Partner will assign the Partnership interest in the Lease to the
Partnership. Leases acquired by each Partnership may initially and
temporarily be held in the name of the Managing General Partner, as nominee,
to facilitate joint-owner operations and the acquisition of properties. The
existence of the unrecorded assignments from the record owner will indicate
-50-
<PAGE>
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 warrant 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 four
geologists (see "Management--Petroleum Development Corporation" for their
resumes), utilizing log and geological data from PDC's historic operations,
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 areas currently being developed is best evaluated 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 distances ranging from about 1,000 to 3,000 feet. Where multiple
zone potential exists, as it frequently does in the proposed areas of
operations, the geologists attempt to optimize well locations to create
wells with two or more productive horizons.
As of March 31, 2000, PDC had acreage available as listed in the
following table within the prospect area.
<TABLE>
<S> <S>
No. of
County Acreage
West Virginia 14,000
Pennsylvania 19,200
Michigan 21,900
Utah 58,800
Colorado 14,200
Total 128,100
</TABLE>
In addition, PDC expects to acquire additional acreage on an ongoing
basis throughout, 1999 and 2000 and beyond for the Program and future
partnerships.
Prospect Area Descriptions
Colorado. The Wattenberg Field, located North and East of Denver,
Colorado, is the most prolific field in the Denver-Julesburg (DJ) basin. The
field, which was discovered in 1970, has produced over 600 billion cubic
feet of natural gas and 2.2 Million barrels of oil.
-51-
Natural gas is the primary hydrocarbon, however many wells will also produce
economic quantities of oil. The gas stream generally has a high heating
value (approximately 1200 btu/mcf) and the purchase price of the gas may
include revenue from the recovery of fluids from the gas stream, as well as
a premium for the higher energy content.
The producing formations are generally atight and require artificial
stimulation for economic production. The typical production profile has an
initial period of high production and relatively rapid decline, followed by
years of relatively shallow decline.
RESERVOIR OVERVIEW
The present structural configuration of the DJ Basin was created by late
cretaceous laramide deformation creating an asymmetric basin with a steeply
dipping western flank and a gently dipping eastern flank. The structural
axis of the dj basin trends approximately north-south, parallel to the
present front range approximately 20 miles to the east of the mountain
front. The Wattenberg Field is a basin-centered gas accumulation in which
stacked reservoirs are found from depths of approximately 4,000 to 8,000
feet. Typical of many basin-centered accumulations, structural positioning
is not a required trapping mechanism. Low reservoir permeability and a long
period of hydrocarbon generation have caused the reservoirs to produce
relatively water free.
GEOLOGIC OVERVIEW
Productive zones are cretaceous in age and include, from youngest to oldest,
Sussex Sandstone, Shannon Sandstone, Niobrara Formation, Codell Sandstone,
D Sandstone, J Sandstone, and Dakota Sandstone. The topographic setting of
the DJ basin is characterized as gently rolling grasslands with surface use
dominated by cattle ranching and agriculture.
SUSSEX SANDSTONE
The Sussex is a fine-to-medium grained, glauconitic feldspanthic-litharenite
that produces in the Hambert and Aristocrat Fields in the northern part of
Wattenberg. The sandstones are thought to have been deposited as shallow-
marine bars on a main shield within the late cretaceous seaway. The Sussex
sandstone is found at depths that range from 3,750 to 5,250 feet. Reservoir
quality varies dramatically from 60 feet of clean sand to 10 feet of thinly
bedded clay-filled sands. Average porosity is approximately 14 percent with
permeability ranging from approximately 0.5 To 1.0 Md. Reservoir
productivity is forecasted based on ultimate production isopachs of
surrounding wells. The reservoir drive mechanism is volumetric expansion.
Original reservoir pressure was approximately 1,450-psi.
NIOBRARA FORMATION
The Niobrara is a succession of limestones (chalks) and calcareous shales
approximately 300 feet thick. The Niobrara was deposited in a relatively
deep-water sedimentary environment associated with the late cretaceous
seaway. The Niobrara is recognized as a source rock and may have provided
the necessary hydrocarbons for the underlying codell. Petroleum production
in the Niobrara is established from the more pure limestone intervals. The
Niobrara is found at depths that range from 6,500 to 7,500 feet. These
limestones are widespread; contain porosities that range from approximately
10 to 15 percent and permeabilities that range from 0.1 To 1.0 Md. Original
reservoir pressure was approximately 4,000-psi.
-52-
CODELL SANDSTONE
The Codell is a fine-grained to very fine-grained sandstone with abundant
associated clays. The sands are widely distributed across Wattenberg and
vary in thickness from 10 to 30 feet. The bioturbated nature of the
sandstone suggests deposition on a shallow marine shelf associated with the
late cretaceous seaway. The Codell sandstone is found at depths that range
from approximately 6,750 to 7,750 feet. Porosity within the codell ranges
from 10 to 20 percent, with permeabilities of 0.1 Md. Because of the
widespread nature of the codell and the relatively uniform rock properties,
productivity, with the appropriate analysis, can be predicted with a high
degree of confidence. Reservoir pressure is approximately 4,000-psi.
Reservoir productivity is forecasted based on ultimate production isopachs
of surrounding wells.
J SANDSTONE
The J sandstone can be subdivided into two distinct members: the fort
collins member and the horsetooth member. The fort collins member is a very
fine-grained moderately sorted quartz arenite and sublitharenite. This
sandstone was deposited in a shallow marine setting within the early
cretaceous seaway and is erosionally overlain by the horsetooth member. The
J sandstone is found at depths that range from 7,500 to 8,400 feet.
Porosities range from 5 to 14 percent, with permeabilities that range from
0.003 To 0.05 Md. The J sandstone reservoir is a single-phase gas reservoir
dominated by volumetric expansion. The original reservoir pressure of wells
developed in the J sandstone has been approximately 1,950-psi. Production
is characterized as dry gas with small amounts of water and condensate. The
produced water is due to condensation within the well bore and does not
reflect water movement from within the reservoir itself. Net sand thickness
ranges from 2 to 90 feet averaging 28 feet. Reservoir productivity is
forecasted based on ultimate production isopachs of surrounding wells.
PRODUCTION
The Wattenberg Field is a mature field and has thousands of producing wells.
Economic success of the Codell/Niobrara and J sandstone reservoirs is
dependent on reservoir quality and on recently improved completion
techniques. The Sussex reservoir is more difficult to interpret because log
analysis can be inconclusive. Sussex development is confined to those areas
that have sufficient existing sussex production, and those areas that have
similar log characteristics to offset producers.
PROPOSED DEVELOPMENT
PDC has acquired the between 78% and 100% of the working interest in
approximately 150 Wattenberg Field locations with expectations to obtain
additional locations. PDC and its partnerships will pay their proportionate
share of the drilling and completion costs for their working interest. The
wells will have third-party royalty and overriding royalty burdens of 20%
or less, none of which are held by PDC or its affiliates.
OIL AND GAS MARKETS
There are extensive gas gathering facilities throughout the Wattenberg
Field, reflecting its long history of production. Gas purchasers include
North American Resources Company (NARCO), Duke Energy and KN Gas Gathering.
In many cases new wells may have the option of choosing a sales market from
two or more purchasers.
Gas in the Wattenberg Field currently sells at a discount to NYMEX pricing
of about $.10 Per Mmbtu and gathering charges are approximately $.30 Per
mmbtu, however the high btu content makes the price per mcf approximately
equal to the NYMEX price per mmbtu.
-53-
Oil produced is a high grade crude, which will be sold to Ultramar Diamond
Shamrock. Recent pricing has been in the range of West Texas Intermediate
(WTI) postings less $1.75 per barrel.
Colorado Piceance Basin Prospect. The Piceance Basin in Western Colorado
has produced more hydrocarbons than any other basin or area in the state.
Since the discovery of the giant rangely oil field in 1902 on its western
flank, the basin has produced over 2.3 trillion cubic feet of natural gas
and over 900 million barrels of oil.
The producing formation in this project is an interval of massively stacked
lenticular "tight sands" which requires artificial stimulation for economic
production. Improved technology for reservoir characterization and
completion has enabled this previously bypassed natural gas resource to
become an economically attractive play. Hydrocarbon production will be
natural gas with very low quantities of associated oil. Typical production
profile is one of an initial period of high production and rapid decline
rate followed by years of relatively slow decline.
STRUCTURAL GEOLOGY AND RESERVOIR OVERVIEW
The Piceance Basin is a complex, asymmetrical basin formed by late
cretaceous laramide tectonism. It has a gently dipping western flank and
a steeply dipping eastern flank. The structural axis extends in a
northwesterly to southeasterly direction approximately 20 miles to the east
of the project. Similar to several other rocky mountain basins, the
piceance is a basin-centered gas accumulation with overpressured gas down
structure from more permeable water-filled reservoirs. Structural position
is not a critical trapping requirement.
Three of the most prolific gas fields in the Piceance Basin, Grand Valley,
Parachute, and Rulison, produce gas from the Mesaverde Group. Deposition
of the Mesaverde Group mostly predates laramide structural development. The
Mesaverde Group is divided into the predominantly non-marine Williams Fork
Formation and the underlying Marine Iles Formation. The Williams Fork is
primary objective in the above gas fields and this project. It is comprised
of massively stacked lenticular sandstones and interstratified shales and
coals. It ranges in depth from surface outcrops along the rim of the basin
to depths of over 11,000 feet in the center of the basin. The underlying
iles formation is comprised of laterally consistent blanket-like marine
deposits including the Rollins, Cozette, Corcoran and Sego Sandstones.
MESAVERDE WILLIAMS FORK AND CAMEO FORMATIONS
The Williams Fork Formation ranges in thickness from 2,000 to 4,000 feet.
Anticipated drilling depths are 7,000 to 10,000 feet. The lower interval
of interstratified coals and sandstones which lies above the Rollins
Sandstone is locally known as the Cameo Formation. The upper interval of
fluvial sandstones is locally known as the Williams Fork or Mesaverde
Formation. Because of authigenic clays, carbonate cement and quartz-
overgrowths, the sandstones have low porosities of 6 to 12 percent and low
matrix permeabilities, often below one microdarcy. Areas with natural
fractures exhibit permeability increases of one to two orders of magnitude.
As recently as 1992, operators were routinely bypassing this interval in
search of the deeper Corcoran-Cozette Sands. Only when the deeper zones
were non-productive would they complete in the Williams Fork. Operators
began experimenting with different completion designs to improve production
in these massively stacked sands. Newer completion designs have nearly
doubled the per well estimated ultimate recoveries. These newer designs
include perforating multiple zones, increasing the size of the proppant
load, and using sophisticated fracturing fluids.
-54-
Advanced type-curve analysis, pressure testing in closely spaced wells and
reservoir simulation are being used to establish optimum well drainage in
this tight lenticular formation. History matching of long term production
data indicates drainage of 10 to 20 acres in 30 years. Pressure testing in
offset wells shows essentially no communication at 40 acre well spacing.
PDC has acquired the rights to develop approximately 7,500 acres of
leasehold in the Piceance Basin with the expectation of obtaining additional
acreage based upon the outcome of the initial wells. Current acreage will
support the drilling of more than 100 wells on 40-acre spacing. Wells
drilled will have third-party royalty and overriding royalty burdens of 20%
or less, none of which are held by PDC or its affiliates. It is anticipated
that PDC and its partnerships will own 100% of the working interest in each
well drilled.
OIL AND GAS MARKETS
There are extensive gas gathering facilities throughout the area. Colorado
Interstate Gas (CIG), Transcolorado, Unocal and Barrett Resources operate
gathering and transmission gas pipelines in the local area. Gas purchasers
include CIG, Transcolorado or others throughout the western united states.
Gas in Piceance Basin has sold recently at a discount to NYMEX of
approximately $.10 To $.20 Per Mmbtu and gathering charges are approximately
$.30 Per Mmbtu.
Northern West Virginia. Northern West Virginia is 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 Upper Devonian and
Mississippian Formations are the targets for wells drilled in this area.
The deepest target reservoirs at depths ranging to a maximum of about
6,000 feet are the Elk, Benson and Riley Sandstones of the Upper Devonian
Chemung Formation. 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 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 Fifth through Keener formations represent the core of the coarse
grained sediments of the Upper Devonian and Mississippian Sands. 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.
-55-
West Central and Southern Pennsylvania. 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 prospect area will come from the Bradford Group (Bradford,
Balltown, Tiona, Speechley and Warren sandstones). These upper Devonian
reservoirs 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 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.
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. 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. 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.
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.
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. Much of the total gas
in place is adsorbed within the organic shale matrix with the remainder
existing as free gas in 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.
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
-56-
<PAGE>
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. 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.
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".)
Southern West Virginia. 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 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%). 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).
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.
Another 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 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. Across the prospect area 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.
-57-
Drilling and Completion Phase
- Most Partnership wells in the Appalachian Basin will be
development wells 3,000 to 5,500 feet deep.
- Most Partnership wells in the Michigan Basin will be development
wells 800-1,200 feet in depth.
- Partnership wells in Colorado may be exploratory or
developmental with depths expected to range from approximately
7,500 to 9,500 feet.
- The Partnership will drill all wells prior to March 31, 2001
for all Partnerships designated "PDC 2000- Limited
Partnership".
- The Managing General Partner will drill Partnership wells near
pipelines, gathering systems, or end users.
- The Partnership will sell production on a competitive basis at
the best available price.
General: The following table shows the anticipated depths and target
formations for planned areas of operations.
<TABLE>
<C> <C> <C>
Location Approximate Planned Target
Well Depths Formations
Appalachian Basin 2,000 - 5,500 feet Various Devonian and
Mississippian
Michigan Basin 800 - 2,000 feet Antrim Shale
Colorado (DJ, Piceance
Basins) 6,500 - 9,500 feet Cretaceous Sands
</TABLE>
The Managing General Partner may drill some shallower or deeper development
Prospects in these areas. If the Managing General Partner drills wells 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. The Managing General
Partner may drill exploratory wells 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, the Managing
General Partner will utilize such funds together with unexpended completion
funds to drill additional development wells. The Operator intends to drill
all of the Partnerships' wells prior to March 31, 2001 for
Partnerships designated "PDC 2000- Limited Partnership".
The Operator, in its sole and absolute discretion, will determine the
depth to which a particular well is drilled based on geologic and other
information available to it. No representations are given in this
prospectus as to the depths and formations to be encountered in each
Partnership's wells, except that the depth of most Appalachian wells will
be at least to a depth of at least 2,000 feet, most Michigan wells will be
at least 800 feet and most Colorado wells will be at least 6,000
feet. The Managing General Partner may substitute another operator or
operators to perform the duties of the Operator, on terms and conditions
-58-
<PAGE>
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 in
the prospectus.
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."
Drilling and Operating Agreement.
- On wells where the Managing General Partner is Operator, it will
have full control over the Partnerships' wells.
-59-
- The operator must commence drilling wells within 180 days after
funding of the Partnership, but not later than, March 31, 2000
for Partnerships designated March 31, 2001 for
Partnerships designated "PDC 2000-_ Limited Partnership".
- The costs charged for drilling and completion, dry holes,
monthly operations will be competitive with rates charges for
similar services and will vary be the location of the wells.
Rates for areas which are currently active are shown in the
table in this section.
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 operator on some of the
Partnership prospects.
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.
The Partnership will pay a proportionate share of total lease,
development, and operating costs, and will 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 Agreement allocates to the Partnership 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.
Theremaining 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
-60-
<PAGE>
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 rendering 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.
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, 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 the "intangible drilling and completion
cost" in the following table, 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
-61-
(b) For each well which the Partnership elects not to
complete, an amount equal to the "intangible dry hole
cost" in the following table, plus actual additional cost
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
proportionately decrease.
<TABLE>
<C> <C> <C> <C> <C>
FOOTAGE BASED RATES
Intangible
Intangible
Target Approximate Drilling and Dry
Hole
Location Formations Well Depth Completion Cost Cost
Northern West
Virginia and Upper Devonian 2,000 - 5,000 feet $60 per foot for $33
per foot
Pennsylvania and Mississippian first 2,200 feet for
the first
plus $16 per foot 2,200
feet plus
for each additional $9 per
foot for
foot below 2,200 each
additional
feet foot
below 2,200
feet
Michigan Antrim Shale 800 - 1,200 feet $138 per foot for $60
per foot for
the first 1,000 the
first 1,000
feet plus $22 per feet
plus $12 for
foot for each each
additional
additional foot foot
below 1,000
below 1,000 feet feet
Wattenberg Cretaceous 6500-7800' $50 per foot $18
per foot
Field Codell
Wattenberg Cretaceous 7000-8000' $67 per foot $21
per foot
Field J Sandstone
Piceance Cretaceous 7000-10,000 $130 per foot $75
per foot
Basin Mesaverde
</TABLE>
*The depth used for determination well charges will be the deepest
penetration by the drilling bit.
-
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 adjust 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.
-63-
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
based upon competitive industry rates for each producing well for operations
and field supervision and a monthly charge of $75 per well for Partnership
accounting, engineering, management, and general and administrative expenses
charges for areas with current operations. 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.
INITIAL PER WELL OPERATING CHARGES
<TABLE>
<C> <C> <C>
WELL LOCATIONS MONTHLY PARTNERSHIP MONTHLY WELLTENDING
ADMINISTRATION FEE
Appalachian Basin* $75 $225
Michigan Basin** $75 $225
Colorado $75 $600
</TABLE>
* Northern West Virginia, Southern West Virginia, Pennsylvania.
** Does not include the monthly charge for operation of the compression,
water disposal, gas injection, and other facilities.
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 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.
The production and accounting charges may be adjusted annually
beginning / 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 1999, 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
- The Partnership will sell the produced gas 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.
- The Partnership will not complete contracts for sale of gas
until after the drilling of the wells.
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.
-63-
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 RNG, 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. 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. Seasonal factors, such as effects of
weather on costs, may impact the Partnership's results. 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 may not 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 , and to
defer the collection of operating expenses when revenues are insufficient
to render full payment.
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 20% (1)
_________________________
Managing 20% Partnership
General Interest (2) 17.50% 16.00%
Partner
Investor 80% Partnership
Partners Interest (2) 70.00% 64.00%
Third Landowners and Over-
Parties riding Royalties 12.50% 20.00%
100.0% 100.0%
____________________
(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 20%.
(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>
-64-
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.
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, Michigan, Pennsylvania
and Colorado; 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
$49,000,000.
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 $25 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 30 years of
operations, drilling in more than 2,000 wells in Tennessee, Ohio,
Pennsylvania, Michigan, Colorado, Montana and West Virginia, PDC's
largest insurance claim has been less than $80,000.
-65-
Upon completion of drilling of a particular Partnership, the Managing
General Partner will convert all Units of general partnership interest of
that Partnership into Units of limited partnership interest of that
Partnership.
The annual cost of such insurance to the Partnership is estimated to
be approximately $625 per well in the year that it is drilled (plus
blowout insurance for Colorado wells of approximately $2,000 per well)
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. Insurance premiums may
increase in the future. The primary effect of increasing premiums cost is
to reduce funds otherwise available for Partnership drilling operations or
for distribution to investors.
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
(ii) either (A) remaining an Investor Partner in the
Partnership and preserving his or her interests in the
Partnership on the same terms and conditions as existed
previously, or (B) receiving cash in an amount equal to
his or her pro-rata share of the appraised value of the
Partnership's net assets;
-66-
(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, so 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. 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.
There will also be competition among operators for drilling
equipment, tubular goods, and drilling crews. Such competition may affect
the ability of each Partnership to acquire Leases suitable for development
by the Partnerships and to develop expeditiously such Leases once they are
acquired.
The marketing of any oil and gas produced by the Partnership will be
affected by a number of factors which are beyond the Partnership's control
and whose exact effect cannot be accurately predicted. These factors
include the volume and prices of 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. 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, 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.
FERC Order No. 636, issued in 1992, requires pipelines to separate
their storage, sales and transportation functions, and establish an
industry-wide structure for "open-access" transportation services 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 made it more competitive. Order No. 637, issued
in February, 2000, further enhanced competitive initiatives, by removing
price caps on short-term capacity release transactions.
-67-
Order No. 637 also enacted other regulatory policies that are intended
to increase the flexibility of interstate gas transportation, to maximize
shippers' supply alternatives, and to encourage domestic natural gas
production in order to meet projected increases in natural gas demand. Such
increases in demand, should they materialize, will come from a number of
sources, including as boiler fuel to meet increase electric power generation
needs and as an industrial fuel that is environmentally preferable to
alternatives such as nuclear power and coal.
The accelerating deregulation of natural gas and electricity
transmission has caused, and will continue to cause, a convergence of the
gas and electric industries. CNG Transmission, which has purchased
Partnership production in the past, is an example of the convergences,
having completed its merger with Dominion Resources, Inc., a large,
Virginia-based provider of electric services, in January, 2000. Demand for
natural gas by the electric power sector is expected to increase through the
next decade. Nearly half of that states have enacted legislation to
increase competition in the electric industry, and convergent mergers of gas
and electric companies typically include safeguards to prevent a gas company
from exercising a marketing advantage in negotiations with an electric
affiliate. Increased competition, particularly where coupled with the
enforcement of stringent environmental regulations, may increase the
electric industry's reliance on natural gas.
Beginning in 1995, the North American Free Trade Agreement ("NAFTA")
eliminated trade and investment barriers in the United States, Canada, and
Mexico, thereby increasing foreign competition for natural gas production.
Legislation that Congress may consider with respect to oil and gas increase
or decrease the demand for the Partnerships' production in the future
depending on whether such legislation is directed toward decreasing demand
or increasing supply.
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 future OPEC actions will have on the quantity
of or 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, and other local distribution companies ("LDCs"), or on the
spot market via open access transportation arrangements through CNG
Transmission, Hope Gas, Eastern American Energy, MichCon, Colorado
Interstate Gas, Equitrans or other pipelines. 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 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 has added to competition in the
natural gas marketplace.
In Order No. 587 and other initiatives, FERC 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 method to access and integrate all gas supply
-68-
<PAGE>
and transportation information on a nationwide basis, so as to create a
national market. Furthermore, parallel developments toward an electronic
marketplace for electric power, mandated by the FERC in Order Nos. 888
and 2000, are serving to create multi-national markets for energy
products 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 and
to improve 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 the past, the Managing General Partner has sold as much as
70% of the gas produced by its wells to Hope Gas or CNG Transmission, both
subsidiaries of Consolidated Natural Gas. Neither 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.
Federal and state regulations will affect production of Partnership
oil and gas. In most areas of operations the production of oil is regulated
by conservation laws and regulations, which set allowable rates of
production and otherwise control the conduct of oil operations.
The Partnership's drilling and production operations will also be
subject to environmental protection regulations established by Federal,
state, and local agencies which in turn may necessitate significant capital
outlays which would materially affect the financial position and business
operations of the Partnership (see "Risk Factors -- Environmental Hazards
and Liabilities").
Certain states control production through regulations establishing the
spacing of wells, limiting the number of days in a given month during which
a well can produce and otherwise limiting the rate of allowable production.
Through regulations enacted to protect against waste, conserve natural
resources and prevent pollution, local, state and Federal environmental
controls will also affect Partnership operations. Such regulations could
affect Partnership operations and could necessitate spending funds on
environmental protection measures, rather than on drilling operations. If
any penalties or prohibitions were imposed on a Partnership for violating
such regulations, that Partnership's operations could be adversely affected.
In prior programs, expenses associated with compliance with
environmental regulations have represented approximately 10-15% of the cost
of drilling and completing wells, and it is expected that similar costs
will be incurred in this program. These costs are included in the
footage-based rates described at "Proposed Activities -- Drilling and
Operating Agreement," above.
Natural Gas Pricing
- The Managing General Partner anticipates that the prices of the
Partnerships' gas will be deregulated, and that the gas will be
sold at fair market value.
Sale of natural gas by the Partnerships will be subject to regulation
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. Deregulated gas production may be sold at market
prices determined by supply, demand, Btu content, pressure, location of
wells, and other factors.
- 69 -
Proposed Regulation
Various legislative proposals in Congress and in state legislatures
could, if enacted, affect the petroleum and natural gas industries. Such
proposals involve, among other things, imposition of direct or indirect
price limitations on natural gas production, 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
Michigan and the Rocky Mountains. As of March 31, 2000, PDC had
approximately 91 employees. PDC will make available to Investor
Partners, upon request, audited financial statements of PDC for the most
recent fiscal year and unaudited financial statements for interim periods.
The Managing General Partner will actively manage and conduct the
business of the Partnerships, devoting such time and talents to such
management as it shall deem reasonably necessary. The Managing General
Partner will have the full and complete power to do any and all things
necessary and incident to the management and conduct of each Partnership's
business. The Managing General Partner will be responsible for maintaining
Partnership bank accounts, collecting Partnership revenues, making
distributions to the Partners, delivering reports to the Partners, and
supervising the drilling, completion, and operation of the Partnerships' gas
wells.
Experience and Capabilities as Driller/Operator
PDC (the "Company" or the "Managing General Partner") will act as
driller/operator for the Program wells. Since 1969 the Company has drilled
over 1,900 wells in West Virginia, Tennessee, Ohio, Michigan, Colorado
and Pennsylvania. The Company currently operates approximately 2,000
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 subcontractors, 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.
-70-
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 68 Chairman, Chief November 1983
Executive Officer
and Director
Steven R. Williams 49 President and March 1983
Director
Dale G. Rettinger 55 Chief Financial July 1980
Officer, Executive
Vice President,
Treasurer
and Director
Roger J. Morgan 72 Secretary and November 1969
Director
Vincent F. D'Annunzio 48 Director February 1989
Jeffrey C. Swoveland 44 Director March 1991
Donald B. Nestor 51 Director March 2000
Thomas E. Riley 47 Vice President April 1996
Marketing and
Acquisitions
Ersel Morgan 56 Vice President April 1995
Production
Eric Stearns 42 Vice President April 1985
Exploration and
Development
Alan Smith 42 Senior Geologist April 1980
Bob Williamson 46 Geologist February 1991
Susan Foster 39 Engineer June 1997
Tom Carpenter 48 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.
-71-
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.
Donald B. Nestor, was elected as a director in March, 2000, is a
Certified Public Accountant and a Partner in the CPA firm of Toothman Rice,
P.L.L.C. and is in charge of the firm's Buckhannon, West Virginia office.
Mr. Nestor has served in that capacity for more than the past five years.
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.
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 prospects and supervision of 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.
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. Prior to joining PDC, Ms. Foster worked as a petroleum engineer
for several Appalachian Basin oil and gas companies.
Tom Carpenter joined PDC on December 1, 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.
-72-
Certain Shareholders of Petroleum Development Corporation
The following table sets forth information as of March 31,
2000, with respect to the common stock of PDC owned by each person who
owns beneficially 5% or more of the outstanding voting common stock, by
all directors individually, and by all directors and officers as a group.
<TABLE> <S> <S> <S>
Amount Percent
Name Beneficially of Class
Owned(1)
Fidelity Management 1,573,800 9.9
James N. Ryan(2)(3) 986,320 6.1
Dimensional Fund Advisors Inc. 906,700 5.7
Steven R. Williams(3) 590,576 3.7
Dale G. Rettinger(3) 527,850 3.3
Roger J. Morgan(4) 82,500 *
Vincent F. D'Annunzio(5) 43,600 *
Jeffrey C. Swoveland(6) 18,094 *
All directors and
executive officers as a
group (6 persons)(7) 2,248,940 13.6
* Less than 1%
</TABLE>
(1) Includes shares over which the person currently holds or shares voting
or investment power. Unless otherwise indicated in the footnotes to
this table, the persons named in this table have sole voting and
investment power with respect to the shares beneficially owned.
(2) Includes 219,738 shares owned jointly with Mr. Ryan's wife, 379,750
shares owned by Mr. Ryan's wife and 64,258 shares owned by Mr. Ryan's
wife as guardian for their minor grandchildren. The balance of the
shares are owned solely by Mr. Ryan.
(3) Includes options to purchase 178,000 shares that such person can
currently exercise or that will become exercisable within 60 days.
(4) Includes options to purchase 47,500 shares that Mr. Morgan can
currently exercise or that will become exercisable within 60 days.
(5) Includes options to purchase 13,600 shares that Mr. D'Annunzio can
currently exercise or that will become exercisable within 60 days.
(6) Includes options to purchase 3,550 shares that Mr. Swoveland can
currently exercise or that will become exercisable within 60 days.
(7) Includes options to purchase 598,650 shares that such persons can
currently exercise or that will become exercisable within 60 days.
Remuneration
No officer or director of the Managing General Partner will receive any
direct remuneration or other compensation from the Partnerships. Such
persons will receive compensation solely from PDC. Information as to
compensation paid by the Managing General Partner to its directors and
executive officers may be obtained from publicly available reports filed by
the Managing General Partner with the Securities and Exchange Commission
pursuant to the Securities Exchange Act of 1934.
Legal Proceedings
The Managing General Partner as driller/operator is subject to certain
minor legal proceedings arising from the normal course of business. Such
legal actions are not considered material to the operations of the Managing
General Partner or the Partnership.
-73-
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
Partnership wells; the terms of the drilling and operating
agreement have not been negotiated by non-affiliated persons.
- The Managing General Partner will providedrilling 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 provided 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.
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.
-74-
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.
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.
-75-
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.
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
-76-
<PAGE>
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 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.
The Managing General Partner will determine arbitrarily the offering price,
which 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 in its own best interest (to 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.
- 77 -
Certain Transactions
As of March 31, 2000, 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--
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 -- --
- 78 -
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 -- --
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 104,174 179,882 -- 4,351,672 -- --
PDC 1997-B 168,987 271,709 -- 7,079,215 -- --
PDC 1997-C 151,081 257,165 -- 6,314,878 -- --
PDC 1997-D 462,989 593,138 19,546,905 -- -- --
PDC 1998-A 131,803 178,267 -- 5,555,181 -- --
- 79 -
PDC 1998-B 178,628 228,938 -- 7,541,358 -- --
PDC 1998-C 195,320 221,506 -- 8,274,895 -- --
PDC 1998-D 513,631 414,444 21,906,777 -- -- --
PDC 1999-A 120,018 173,267 -- 5,047,537 -- --
PDC 1999-B 138,497 167,131 -- 5,372,762 -- --
PDC 1999-C 177,189 298,744 -- 7,408,976 -- --
PDC 1999-D(1) 467,734 795,958 19,550,451 -- -- --
____________________
(1) Partnership funded in December 1999.
</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 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.
- 80 -
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. PDC
2000 Drilling Program (the "Program") is the eighth public drilling program
sponsored by PDC as general partner. The various drilling programs
sponsored by PDC, including the first four limited partnerships in the
Program (PDC 1998-A through -D Limited Partnerships) have raised a total of
$202,846,596.
- 81 -
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 Appalachian Basin. All
of the partnerships since and including 1986 were targeted at shallow
development gas wells. 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. INVESTOR PARTNERS IN THE OFFERING COVERED
BY THIS PROSPECTUS SHOULD NOT ASSUME THAT THEY WILL EXPERIENCE RETURNS, IF
ANY, COMPARABLE TO THOSE EXPERIENCED BY INVESTORS IN PRIOR PROGRAMS.
- 82 -
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 --
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 --
- 83 -
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 11/97 208.85 20,000 4,166,946 --
PDC 1997-B 9/97 3/98 337.97 20,000 6,759,470 --
PDC 1997-C 11/97 5/98 302.16 20,000 6,043,257 --
PDC 1997-D 12/97 6/98 925.98 20,000 18,519,579 --
PDC 1998-A 6/98 12/98 263.61 20,000 5,272,135 --
PDC 1998-B 9/98 3/99 357.25 20,000 7,145,101 --
PDC 1998-C 11/98 5/99 390.64 20,000 7,812,783 --
PDC 1998-D 12/98 7/99 1,026.26 20,000 20,525,261 --
PDC 1999-A 5/99 11/99 240.08 20,000 4,800,739 --
PDC 1999-B 9/99 3/00 278.00 20,000 5,539,893 --
PDC 1999-C 11/99 5/00(2) 354.38 20,000 7,087,559 --
-84-
PDC 1999-D 12/99 7/00(3) 935.47 20,000 18,709,342 --
______________
</TABLE>
(1) Cash distribution made each month since date of first distribution.
(2) Partnership closed on November 15, 1999. Wells were drilled in the
fourth quarter of 1999 and the first quarter of 2000; first revenue
distribution commenced in May, 2000.
(3) Partnership closed on December 31, 1999. Wells were drilled in the
first quarter of 2000; first revenue distribution to commence in
July, 2000.
INVESTORS SHOULD NOT CONSIDER OPERATING RESULTS OBTAINED BY THESE PRIOR
PARTNERSHIPS AS INDICATIVE OF THE OPERATING RESULTS OBTAINABLE BY THE
PARTNERSHIPS.
- 85 -
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 March 31, 2000. All of the wells drilled were
Development Wells, except as otherwise noted.
<TABLE>
<S> <S> <S> <S> <S> <S> <S>
Productive Well Table
March 31, 2000
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
- 9 1 - 5.5 .6
PDC 1987 - 7 - - 2.6 -
PDC 1988 - 5 1 - 4.1 .8
PDC 1988-B - 5 - - 4.7 -
PDC 1988-C - 9 1 - 7.0 .8
PDC 1989-P - 8 1 - 7.8 .9
PDC 1989-A - 6 1 - 5.5 .9
PDC 1989-B - 19 2 - 17.0 1.8
PDC 1990-A - 7 1 - 6.0 .9
PDC 1990-B - 11 - - 10.3 -
PDC 1990-C - 15 2 - 14.4 2.0
PDC 1990-D - 16 1 - 15.8 1.0
PDC 1991-A - 13 - - 12.0 -
PDC 1991-B - 8 2 - 7.2 2.0
- 86 -
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 - 80 5 - 62.3 4.3
PDC 1997-A - 21 1 - 11.1 0.1
PDC 1997-B - 34 2 - 23.4 2.0
PDC 1997-C - 28 2 - 19.5 1.1
PDC 1997-D - 94 7 - 72.7 4.5
PDC 1998-A - 29 2 - 19.2 2.0
PDC 1998-B - 41 2 - 26.9 1.9
PDC 1998-C - 37 1 - 29.9 1.0
PDC 1998-D - 89(4) 8(5) - 70.8(4) 7.6(5)
-87-
PDC 1999-A - 24 0 - 19.5 0
PDC 1999-B - 26 1 - 21.0 0.5
PDC 1999-C(6) - 24 2 - 20.9 2.0
PDC 1999-D(7) - 51 0 - 37.5 0
Total ...... 41 1,127 92 41 916.2 80.2
_____________________
</TABLE>
(1) Gross wells include all wells in which the partnerships owned a
Working Interest.
(2) Net wells are the number of gross wells multiplied by the percentage
Working Interest owned by the partnerships in the gross wells.
(3) The dry hole indicated represents an exploratory well.
(4) One of the gas wells represents an exploratory well with a net
interest of .9.
(5) Three of the dry holes represent exploratory wells with a net
interest of 2.7.
(6) Partnership funded in November 1999. Wells were drilled in the
fourth quarter of 1999 and first quarter of 2000.
(7) Partnership funded in December 1999. Wells were drilled in first
quarter of 2000.
INVESTOR SHOULD NOT CONSIDER OPERATING RESULTS OBTAINED BY THESE PRIOR
PARTNERSHIPS AS INDICATIVE OF THE OPERATING RESULTS OBTAINABLE BY THE
PARTNERSHIPS.
- 88 -
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 March 31, 2000.
<TABLE>
<S> <S> <S> <S> <S>
Participants' Payout Table
March 31, 2000
Revenues Before Deducting
Operating Costs(3)
Total
Expendi-
Investors' tures Total During Three
Funds Including As of Months Ended
Invested(1) Operating March March 31,
Costs(2) 31, 2000 2000
Pennwest
Petroleum
Group 1984 $2,093,125 $3,226,515 $2,145,276 $ 13,009
Pennwest
Petroleum
Group 1,976,250 3,068,422 1,752,336 21,779
Petrowest
Gas Group
1986-A 956,250 1,533,545 1,000,178 10,855
Petrowest
Gas Group
1987 1,143,250 1,862,608 1,476,403 15,212
Petrowest
Gas Group
1987-B 983,875 1,475,101 770,659 6,946
PDC 1987 454,750 722,797 520,039 5,328
PDC 1988 770,100 1,268,527 1,105,182 11,296
PDC 1988-B 841,500 1,282,353 577,023 8,306
PDC 1988-C 1,326,000 2,054,769 1,121,512 15,872
PDC 1989-P 1,523,625 2,355,572 1,719,079 21,716
PDC 1989-A 1,028,500 1,650,275 1,283,805 27,111
PDC 1989-B 3,153,500 4,608,161 2,577,993 30,182
PDC 1990-A 1,195,100 1,684,144 698,610 8,858
PDC 1990-B 1,887,850 2,760,514 1,502,921 22,517
PDC 1990-C 2,956,300 4,304,972 2,182,275 45,307
PDC 1990-D 3,132,674 4,486,858 2,204,344 38,242
- 89 -
PDC 1991-A 2,328,150 3,358,138 2,005,402 29,826
PDC 1991-B 1,583,975 2,230,233 1,135,232 20,093
PDC 1991-C 2,325,600 3,305,225 1,760,257 34,245
PDC 1991-D 4,469,725 6,189,496 2,403,048 53,372
PDC 1992-A 2,472,396 3,364,002 969,279 17,809
PDC 1992-B 2,532,246 3,581,710 2,056,124 50,078
PDC 1992-C 5,430,563 7,745,731 5,114,338 113,105
PDC 1993-A 2,647,750 3,991,568 3,859,967 52,261
PDC 1993-B 2,130,620 2,825,249 1,213,962 29,680
PDC 1993-C 2,665,865 3,544,036 1,302,421 36,374
PDC 1993-D 2,545,375 3,305,303 1,386,991 40,933
PDC 1993-E 6,438,950 7,854,310 3,391,755 99,707
PDC 1994-A 1,798,563 2,421,021 847,679 20,404
PDC 1994-B 2,353,579 3,057,210 1,288,489 41,973
PDC 1994-C 2,052,636 2,646,448 972,772 34,616
PDC 1994-D 6,605,166 8,452,682 3,159,055 106,062
PDC 1995-A 1,282,403 1,701,472 759,777 25,525
PDC 1995-B 1,625,442 2,013,591 537,001 15,412
PDC 1995-C 1,850,184 2,354,203 659,603 22,578
PDC 1995-D 7,137,437 8,897,537 2,676,583 107,817
PDC 1996-A 2,241,294 2,848,381 1,409,892 58,852
PDC 1996-B 2,335,695 2,907,021 1,053,241 55,683
PDC 1996-C 3,433,436 4,173,479 1,098,985 59,665
PDC 1996-D 13,312,502 16,102,195 3,880,670 248,017
PDC 1997-A 3,625,243 4,312,173 938,713 54,882
PDC 1997-B 5,880,739 6,967,216 1,223,918 109,969
PDC 1997-C 5,257,634 6,361,567 1,465,125 142,040
PDC 1997-D 16,112,034 19,314,715 2,361,856 315,747
- 90 -
PDC 1998-A 4,586,758 5,509,743 836,995 176,964
PDC 1998-B 6,216,237 7,409,899 937,753 288,915
PDC 1998-C 6,797,121 8,117,172 1,064,616 267,413
PDC 1998-D 17,856,977 20,960,407 1,588,085 488,030
PDC 1999-A 4,176,643 4,865,975 336,379 140,713
PDC 1999-B 4,819,707 5,631,303 380,624 127,645
PDC 1999-C(4) 6,166,176 7,087,559 - -
PDC 1999-D(5) 16,277,127 18,709,342 - -
_____________________
</TABLE>
(1) Total Subscriptions, less commissions, management fee, and offering
costs.
(2) Includes the total of the subscriptions, assessments, funds advanced
by the Managing General Partner to the general or limited
partnerships, inclusive of operating costs. None of the partnerships
has borrowed any funds.
(3) Represents the accrued gross revenues credited to the participants
from oil and gas revenues net of royalties to landowners, overriding
royalty interest, and other burdens, excluding interest income.
(4) Partnership funded in November 1999; wells were drilled in the
fourth quarter of 1999 and first quarter of 2000; first revenue
distribution commenced in May, 2000.
(5) Partnership funded in December 1999; wells were drilled in the first
quarter of 2000; first revenue distribution to commence in July,
2000.
INVESTOR SHOULD NOT CONSIDER OPERATING RESULTS OBTAINED BY THESE PRIOR
PARTNERSHIPS AS INDICATIVE OF THE OPERATING RESULTS OBTAINABLE BY THE
PARTNERSHIPS.
- 91 -
<TABLE>
<S> <S> <S> <S> <S> <S> <S> <S>
Participants' Net Cash Table
March 31, 2000
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- March March March March ion 29
ing Costs 31, 2000 31, 2000 31, 31, Tax (5)
2000 2000 Credit
(1) (2)
Pennwest
Petroleum
Group
1984 $2,093,125 $2,462,500 $1,381,261 $ 1,199 $1,311,759 $ 1,199
$527,682
Pennwest
Petroleum
Group
1985-A 1,976,250 2,325,000 1,008,913 7,078 965,641 7,078
636,447
Petrowest
Gas Group
1986-A 956,250 1,125,000 591,632 5,066 564,862 5,066
458,676
Petrowest
Gas Group
1987 1,143,250 1,345,000 958,795 4,450 916,175 4,450
516,732
Petrowest
Gas Group
1987-B 983,875 1,157,500 453,058 1,098 426,688 1,098
362,356
PDC 1987 454,750 535,000 332,241 1,450 314,669 1,450
232,550
PDC 1988 770,100 906,000 742,655 6,031 705,766 6,031
474,208
PDC 1988-B 841,500 990,000 284,671 1,153 260,831 1,153
258,876
PDC 1988-C 1,326,000 1,560,000 626,743 4,706 583,687 4,706
490,847
PDC 1989-P 1,523,625 1,792,500 1,156,007 10,177 1,078,122 10,177
774,636
PDC 1989-A 1,028,500 1,210,000 843,531 18,549 800,447 18,549
533,471
PDC 1989-B 3,153,500 3,710,000 1,679,832 9,219 1,574,196 9,219
764,067
PDC 1990-A 1,195,100 1,406,000 420,466 1,985 360,253 1,985
139,201
PDC 1990-B 1,887,850 2,221,000 963,406 2,759 925,646 2,759
616,732
PDC 1990-C 2,956,300 3,478,000 1,355,303 18,508 1,286,065 18,508
627,897
PDC 1990-D 3,132,674 3,685,500 1,402,986 17,383 1,342,119 17,383
813,556
- 92 -
PDC 1991-A 2,328,150 2,739,000 1,386,264 12,594 1,282,799 12,594
838,653
PDC 1991-B 1,583,975 1,863,500 768,499 11,783 739,624 11,783
487,365
PDC 1991-C 2,325,600 2,736,000 1,191,032 20,573 1,104,432 20,573
740,147
PDC 1991-D 4,469,725 5,258,500 1,472,052 23,339 1,399,040 23,339
951,210
PDC 1992-A 2,472,396 2,908,700 513,977 4,071 435,253 4,071
373,093
PDC 1992-B 2,532,246 2,979,100 1,453,514 32,991 1,392,457 32,991
876,034
PDC 1992-C 5,430,563 6,388,900 3,757,507 74,251 3,635,393 74,251
1,706,425
PDC 1993-A 2,647,750 3,026,000 2,894,399 31,154 2,700,223 31,154
127,783
PDC 1993-B 2,130,620 2,435,000 823,714 16,796 764,807 16,796
--
PDC 1993-C 2,665,865 3,046,700 805,085 15,901 748,699 15,901
--
PDC 1993-D 2,545,375 2,909,000 990,688 25,941 949,450 25,941
--
PDC 1993-E 6,438,950 7,358,800 2,896,245 56,801 2,747,297 56,801
--
PDC 1994-A 1,798,563 2,055,500 482,158 8,555 442,188 8,555
--
PDC 1994-B 2,353,579 2,689,804 921,083 22,824 865,825 22,824
--
PDC 1994-C 2,052,636 2,345,870 672,194 20,275 615,757 20,275
--
PDC 1994-D 6,605,166 7,548,761 2,255,134 60,569 2,068,279 60,569
--
PDC 1995-A 1,282,403 1,465,603 523,908 15,450 475,849 15,450
--
PDC 1995-B 1,625,442 1,857,648 381,058 7,254 325,050 7,254
--
PDC 1995-C 1,850,184 2,114,496 419,896 8,899 363,099 8,899
--
PDC 1995-D 7,137,437 8,157,071 1,936,117 58,961 1,725,421 58,961
--
PDC 1996-A 2,241,294 2,576,200 1,137,711 36,392 1,002,893 36,392
--
PDC 1996-B 2,335,695 2,684,707 830,927 40,247 706,011 40,247
--
PDC 1996-C 3,433,436 3,946,478 889,984 37,446 772,709 37,446
--
PDC 1996-D 13,312,502 15,301,726 3,080,202 151,814 2,722,112 151,814
--
PDC 1997-A 3,625,243 4,166,946 793,486 34,758 699,565 34,758
--
PDC 1997-B 5,880,739 6,759,470 1,016,171 96,449 866,770 96,449
--
PDC 1997-C 5,257,634 6,043,257 1,146,815 98,230 824,904 98,230
--
PDC 1997-D 16,112,034 18,519,579 1,566,720 166,349 1,182,835 166,349
--
- 93 -
PDC 1998-A 4,586,758 5,272,135 599,386 112,657 448,359 112,657
--
PDC 1998-B 6,216,237 7,145,101 672,955 191,913 579,557 191,813
--
PDC 1998-C 6,797,121 7,812,783 760,227 166,031 494,570 166,031
--
PDC 1998-D 17,856,977 20,525,261 1,152,939 315,208 691,375 315,208
--
PDC 1999-A 4,176,643 4,800,739 271,143 106,354 131,554 106,354
--
PDC 1999-B 4,819,707 5,539,893 289,213 102,009 102,009 102,009
--
PDC
1999-C(6) 6,166,176 7,087,559 -- -- -- --
--
PDC
1999-D(7) 16,277,127 18,709,342 -- -- -- --
--
_____________________
</TABLE>
(1) Total Subscriptions, less commissions, management fee, and offering
costs.
(2) Includes the total of the subscriptions, assessments, funds advanced
by the Managing General Partner to the general or limited
partnerships, exclusive of operating costs. None of the
partnerships has borrowed any funds.
(3) Represents the accrued gross revenues credited from oil and gas
production, excluding operating costs, Landowners' Royalty
Interests, Overriding Royalty Interests, and other burdens.
(4) Represents the net cash distributed to the partnerships. All cash
distributions to the partners were made from operations and
constituted ordinary income.
(5) Wells drilled after December 31, 1992 do not qualify for the credit.
(6) Partnership funded in November 1999; wells were drilled in the
fourth quarter of 1999 and the first quarter of 2000; first revenue
distribution commenced in May, 2000.
(7) Partnership funded in December 1999; wells were drilled in the first
quarter of 2000; first revenue distribution to commence in July,
2000.
INVESTORS SHOULD NOT CONSIDER OPERATING RESULTS OBTAINED BY THESE PRIOR
PARTNERSHIPS AS INDICATIVE OF THE OPERATING RESULTS OBTAINABLE BY THE
PARTNERSHIPS.
- 94 -
<TABLE>
<S> <S> <S> <S>
Managing General Partner's Payout Table
March 31, 2000
Revenues Before Deducting
Total Expenditures Operating Costs(2)
Including Total As of During Three Months
Partnership Operating Costs(1) March 31, 2000 Ended March 31, 2000
Pennwest Petroleum
Group 1984 $ 160,664 $273,452 $ 2,125
Pennwest Petroleum
Group 1985-A 150,187 230,775 3,566
Petrowest Gas
Group 1986-A 80,708 159,886 1,850
Petrowest Gas
Group 1987 98,028 227,991 2,523
Petrowest Gas
Group 1987-B 77,638 119,342 1,164
PDC 1987 38,044 81,214 899
PDC 1988 66,752 179,619 1,922
PDC 1988-B 67,495 95,255 1,426
PDC 1988-C 109,146 178,392 2,655
PDC 1989-P 123,971 269,062 3,610
PDC 1989-A 220,894 318,730 6,778
PDC 1989-B 555,665 620,565 7,546
PDC 1990-A 196,163 161,320 2,214
PDC 1990-B 340,817 365,670 5,629
PDC 1990-C 518,425 510,749 11,327
PDC 1990-D 526,559 495,306 9,560
PDC 1991-A 403,392 486,528 7,457
PDC 1991-B 258,360 273,828 5,023
PDC 1991-C 391,424 425,548 8,561
PDC 1991-D 702,841 554,126 13,343
PDC 1992-A 296,250 85,543 -0-
PDC 1992-B 421,255 503,612 12,519
PDC 1992-C 907,078 1,208,446 28,276
- 95 -
PDC 1993-A 489,764 838,624 11,472
PDC 1993-B 317,153 258,603 6,515
PDC 1993-C 388,139 243,706 7,985
PDC 1993-D 360,959 272,793 8,985
PDC 1993-E 803,618 682,636 21,887
PDC 1994-A 536,176 202,143 5,101
PDC 1994-B 676,673 312,938 10,493
PDC 1994-C 585,896 240,452 8,711
PDC 1994-D 1,866,830 763,906 26,380
PDC 1995-A 376,963 182,989 6,074
PDC 1995-B 441,730 123,802 3,462
PDC 1995-C 518,349 155,677 5,317
PDC 1995-D 1,955,884 631,777 23,903
PDC 1996-A 656,590 352,473 14,713
PDC 1996-B 673,947 263,311 13,921
PDC 1996-C 983,379 274,746 14,916
PDC 1996-D 3,864,275 970,167 62,004
PDC 1997-A 1,014,038 234,678 13,720
PDC 1997-B 1,649,600 305,978 27,492
PDC 1997-C 1,468,948 366,281 35,510
PDC 1997-D 4,338,204 590,463 78,937
PDC 1998-A 1,206,093 209,249 44,241
PDC 1998-B 1,620,260 234,438 72,229
PDC 1998-C 1,775,378 266,153 66,853
PDC 1998-D 4,573,031 397,020 122,007
PDC 1999-A 1,060,471 84,095 35,178
PDC 1999-B 1,227,780 95,156 31,911
PDC 1999-C(3) 1,541,544 - -
PDC 1999-D(4) 4,069,282 - -
_____________________
</TABLE>
- 96 -
(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 November 1999; wells were drilled during the
fourth quarter of 1999 and the first quarter of 2000; first revenue
distribution commenced in May, 2000.
(4) Partnership funded in December 1999; wells were drilled in the first
quarter of 2000; first revenue distribution to commence in July,
2000.
INVESTORS SHOULD NOT CONSIDER OPERATING RESULTS OBTAINED BY THESE PRIOR
PARTNERSHIPS AS INDICATIVE OF THE OPERATING RESULTS OBTAINABLE BY THE
PARTNERSHIPS.
- 97 -
<TABLE>
<S> <S> <S> <S> <S> <S> <S>
Managing General Partner's Net Cash Table
March 31, 2000
Total Revenues
After Deducting Cash
Operating Costs(2) Distributions(3)
Total
Expendi-
Aggregate
itures Three Three
Section
Net of Total Ended Total Months 29
Tax
Operating As of March March As of March Ended March
Credits
Partnership Costs 31, 2000 31, 2000 31, 2000 31, 2000 (4)
Pennwest
Petroleum
Group 1984 $ 129,605 $242,393 $ 1,814 $238,735 $ 1,814
$27,773
Pennwest
Petroleum
Group 1985-A 122,368 202,956 3,179 200,679 3,179
33,497
Petrowest
Gas Group
1986-A 59,210 138,388 1,545 133,948 1,545
24,141
Petrowest
Gas Group
1987 70,789 200,752 1,957 194,540 1,957
27,196
Petrowest
Gas Group
1987-B 60,921 102,626 857 98,251 857
19,071
PDC 1987 28,158 71,328 695 68,684 695
12,239
PDC 1988 47,684 160,551 1,645 155,002 1,645
24,958
PDC 1988-B 52,105 79,866 1,050 75,259 1,050
13,625
PDC 1988-C 82,105 151,351 2,067 144,034 2,067
25,834
PDC 1989-P 94,342 239,433 3,003 226,045 3,003
40,770
PDC 1989-A 114,278 212,114 4,637 201,343 4,637
133,368
PDC 1989-B 350,389 415,289 2,305 388,880 2,305
191,017
PDC 1990-A 132,789 97,946 496 82,893 496
34,800
PDC 1990-B 209,761 234,614 690 225,174 690
154,183
PDC 1990-C 328,478 320,802 4,627 303,492 4,627
156,974
PDC 1990-D 348,075 316,823 4,346 301,606 4,346
203,389
- 98 -
PDC 1991-A 258,683 341,818 3,148 315,952 3,148
209,663
PDC 1991-B 175,997 191,466 2,946 185,691 2,946
121,841
PDC 1991-C 258,400 292,524 5,143 270,874 5,143
185,037
PDC 1991-D 496,639 347,924 5,835 329,671 5,835
237,803
PDC 1992-A 274,711 64,004 -0- 44,323 -0-
-0-
PDC 1992-B 281,361 363,719 8,248 351,508 8,248
219,009
PDC 1992-C 603,396 904,764 18,562 880,342 18,562
426,606
PDC 1993-A 294,194 643,054 6,839 600,430 6,839
28,751
PDC 1993-B 236,736 178,186 3,687 165,255 3,687
--
PDC 1993-C 296,207 151,773 3,490 139,396 3,490
--
PDC 1993-D 282,819 194,653 5,694 185,601 5,694
--
PDC 1993-E 715,438 594,456 12,468 561,760 12,468
--
PDC 1994-A 449,641 115,608 2,139 106,834 2,139
--
PDC 1994-B 588,395 224,660 5,706 210,845 5,706
--
PDC 1994-C 513,159 167,715 5,102 153,606 5,102
--
PDC 1994-D 1,651,292 548,368 15,065 501,654 15,065
--
PDC 1995-A 320,601 126,628 3,677 114,613 3,677
--
PDC 1995-B 406,361 88,434 1,630 74,432 1,630
--
PDC 1995-C 462,546 99,874 2,096 85,675 2,096
--
PDC 1995-D 1,784,359 460,252 13,072 407,578 13,072
--
PDC 1996-A 560,324 256,207 9,098 222,503 9,098
--
PDC 1996-B 583,924 173,288 7,192 142,059 7,192
--
PDC 1996-C 858,359 149,726 9,361 120,407 9,361
--
PDC 1996-D 3,328,126 434,019 37,953 344,497 37,953
--
PDC 1997-A 906,311 126,951 8,689 103,471 8,689
--
PDC 1997-B 1,470,185 126,563 (9,804) 89,213 (9,804)
--
PDC 1997-C 1,314,409 211,742 24,557 131,264 24,557
--
PDC 1997-D 4,028,009 280,267 41,586 184,296 41,586
--
- 99 -
PDC 1998-A 1,146,758 149,846 28,164 112,089 28,164
--
PDC 1998-B 1,554,059 168,237 47,978 144,888 47,978
--
PDC 1998-C 1,699,280 190,055 41,507 123,641 41,507
--
PDC 1998-D 4,464,244 288,233 78,801 172,842 78,801
--
PDC 1999-A 1,044,161 67,785 26,588 32,888 26,588
--
PDC 1999-B 1,204,927 72,303 25,502 25,502 25,502
--
PDC 1999-C(5) 1,541,544 -- -- -- --
--
PDC 1999-D(6) 4,069,282 -- -- -- --
--
</TABLE>
_____________________
(1) Includes Managing General Partner share of drilling costs, exclusive
of operating costs.
(2) Represents the accrued gross revenues credited from oil and gas
production, excluding operating costs, landowners' royalty
interests, Overriding Royalty Interests, and other burdens.
(3) Represents the net cash received from the partnerships' cash
distributions. All cash distributions to the managing general
partner were made from operations.
(4) Wells drilled after December 31, 1992 do not qualify for the credit.
(5) Partnership funded in November 1999; wells were drilled during the
fourth quarter of 1999 and the first quarter of 2000; first revenue
distribution commenced in May, 2000.
(6) Partnership funded in December 1999; wells were drilled in the first
quarter of 2000; first revenue distribution to commence in July,
2000.
INVESTORS SHOULD NOT CONSIDER OPERATING RESULTS OBTAINED BY THESE PRIOR
PARTNERSHIPS AS INDICATIVE OF THE OPERATING RESULTS OBTAINABLE BY THE
PARTNERSHIPS.
- 100 -
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 March 31, 2000, 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 do 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 Credits(1) Savings(2) Ratio(3)
*Pennwest
Petroleum
Group 1984 70.87% 27.09% 21.43% 67.99% 1.4:1
*Pennwest
Petroleum
Group 1985-A 69.51% 28.02% 27.37% 72.69% 1.5:1
*Petrowest
Gas Group
1986-A 70.10% 28.64% 40.77% 85.80% 1.8:1
*Petrowest
Gas Group
1987 63.09% 33.77% 38.42% 74.17% 2.3:1
*Petrowest
Gas Group
1987-B 68.70% 26.67% 31.31% 66.78% 2.0:1
*PDC 1987 70.30% 32.39% 43.47% 81.58% 2.5:1
*PDC 1988 68.57% 33.25% 52.34% 86.30% 2.9:1
*PDC 1988-B 66.70% 32.35% 26.15% 59.31% 1.9:1
- 101 -
*PDC 1988-C 69.20% 30.23% 31.46% 64.75% 2.1:1
*PDC 1989-P 63.68% 31.40% 43.22% 75.21% 2.5:1
*PDC 1989-A 69.80% 35.16% 44.09% 79.62% 2.6:1
*PDC 1989-B 69.10% 28.54% 20.59% 53.39% 1.7:1
*PDC 1990-A 67.92% 18.85% 9.90% 38.94% 1.2:1
*PDC 1990-B 71.50% 23.31% 27.77% 59.69% 1.9:1
*PDC 1990-C 70.60% 26.57% 18.05% 50.98% 1.6:1
*PDC 1990-D 69.70% 29.14% 22.07% 55.68% 1.8:1
*PDC 1991-A 69.80% 22.20% 30.62% 60.61% 2.0:1
*PDC 1991-B 67.00% 26.88% 26.15% 56.58% 1.9:1
*PDC 1991-C 69.60% 27.22% 27.05% 58.73% 1.9:1
*PDC 1991-D 69.80% 23.47% 18.09% 48.50% 1.6:1
*PDC 1992-A 68.24% 18.02% 12.83% 40.95% 1.3:1
*PDC 1992-B 69.60% 28.18% 29.41% 61.95% 2.0:1
*PDC 1992-C 69.20% 30.94% 26.71% 60.19% 1.9:1
*PDC 1993-A 69.00% 39.19% 4.22% 40.89% 1.2:1
*PDC 1993-B 68.10% 24.17% -- 34.06% 0.9:1
*PDC 1993-C 68.80% 22.27% -- 33.58% 0.9:1
*PDC 1993-D 68.60% 20.64% -- 32.85% 0.9:1
*PDC 1993-E 67.60% 23.85% -- 33.77% 0.9:1
*PDC 1994-A 87.70% 4.93% -- 36.68% 0.9:1
*PDC 1994-B 89.40% 6.67% -- 38.04% 1.0:1
*PDC 1994-C 89.70% 5.52% -- 37.71% 1.0:1
*PDC 1994-D 89.90% 6.25% -- 38.08% 1.0:1
PDC 1995-A 85.66% 12.32% -- 38.80% 1.0:1
PDC 1995-B 89.02% 5.62% -- 37.48% 0.9:1
PDC 1995-C 89.71% 5.08% -- 37.54% 0.9:1
PDC 1995-D 89.94% 5.08% -- 37.63% 1.0:1
PDC 1996-A 89.94% 6.87% -- 38.34% 1.0:1
PDC 1996-B 86.82% 7.74% -- 37.45% 0.9:1
- 102 -
PDC 1996-C 89.42% 4.43% -- 37.16% 0.9:1
PDC 1996-D 89.49% 4.03% -- 37.03% 0.9:1
PDC 1997-A 89.50% 2.73% -- 36.52% 0.9:1
PDC 1997-B 89.50% 2.65% -- 36.49% 0.9:1
PDC 1997-C 89.50% 3.70% -- 36.91% 0.9:1
PDC 1997-D 89.50% 2.30% -- 36.35% 0.9:1
PDC 1998-A 89.50% 2.57% -- 36.46% 0.9:1
PDC 1998-B 89.50% 2.95% -- 36.61% 0.9:1
PDC 1998-C 89.50% 2.31% -- 36.35% 0.9:1
PDC 1998-D 89.50% 1.31% -- 35.96% 0.9:1
PDC 1999-A 89.50% 0.44% -- 35.61% 0.9:1
PDC 1999-B 89.50% 0.15% -- 35.50% 0.9:1
PDC 1999-C(4) 89.50% 0.00% -- 35.44% 0.9:1
PDC 1999-D(5) 89.50% 0.00% -- 35.44% 0.9:1
</TABLE>
*Partnerships in existence for over five years.
_____________________
(1) Wells drilled after December 31, 1992 do not qualify for the credit.
(2) The Estimated Federal Tax Savings column reflects the percentage
savings in taxes which would have been paid by an investor had he
not had the use of the various deductions and credits available to
a Partner in the Program and it assumes full use of deductions and
tax credits at maximum Federal tax rates of 50% in 1984-1986, 40% in
1987 and 1988, and 33% in 1989 and 1990, 31% in 1991-1992, 36% in
1993, and 39.6% in 1994 and thereafter.
(3) Total deductions plus 200% of credits generated for partnerships
first offered before December 31, 1986. Total deductions plus 350%
of credits generated for partnerships offered after December 31,
1986.
(4) Partnership funded in November 1999.
(5) Partnership funded in December 1999.
INVESTORS SHOULD NOT CONSIDER OPERATING RESULTS OBTAINED BY THESE PRIOR
PARTNERSHIPS AS INDICATIVE OF THE OPERATING RESULTS OBTAINABLE BY THE
PARTNERSHIPS.
- 103 -
Percentage of Gross Return on Subscriptions Through
March 31, 2000
From Cash Distributions, Tax Savings from
Deductions and Tax Credits(1)
<TABLE>
<S> <S> <S> <S> <S> <S>
TOTAL
CASH TOTAL TAX RETURN
DISTRI- CASH DEDUC- OF CASH
BUTIONS SEC- AND TIONS, AND TAX
YEARS/MONTHS
CUMULATIVE TION 29 TAX TAX DEDUC- ALL WELLS
PROGRAM (2) CREDITS(3) CREDIT EFFECTED(4) TIONS(5) PRODUCING
*Pennwest 1984 53.23% 21.43% 74.66% 50.48% 125.14% 15/0
*Pennwest 1985-A 41.30% 27.37% 68.68% 49.22% 117.89% 14/1
**Petrowest 1986 49.95% 40.77% 90.73% 48.98% 139.71% 13/0
**Petrowest 1987 67.88% 38.42% 106.29% 39.63% 145.92% 12/3
**Petrowest 1987-B 36.78% 31.31% 68.09% 39.29% 107.37% 12/0
**PDC 1987 58.52% 43.47% 101.98% 42.22% 144.21% 11/10
**PDC 1988 77.17% 52.34% 129.51% 38.03% 167.54% 11/4
**PDC 1988-B 26.30% 26.15% 52.45% 37.12% 89.57% 11/0
**PDC 1988-C 37.31% 31.46% 68.78% 37.27% 106.04% 10/10
**PDC 1989-P 59.51% 43.22% 102.73% 35.80% 138.52% 10/4
**PDC 1989-A 65.82% 44.09% 109.91% 39.73% 149.64% 10/0
**PDC 1989-B 42.24% 20.59% 62.84% 36.70% 99.53% 9/10
**PDC 1990-A 25.62% 9.90% 35.52% 32.51% 68.03% 9/5
**PDC 1990-B 41.48% 27.77% 69.25% 35.71% 104.96% 9/3
**PDC 1990-C 36.64% 18.05% 54.69% 36.81% 91.50% 8/11
**PDC 1990-D 36.24% 22.07% 58.32% 37.56% 95.88% 8/10
**PDC 1991-A 46.70% 30.62% 77.32% 33.67% 110.99% 8/5
**PDC 1991-B 39.43% 26.15% 65.59% 34.18% 99.77% 8/2
**PDC 1991-C 40.07% 27.05% 67.12% 35.55% 102.68% 8/0
**PDC 1991-D 26.46% 18.09% 44.55% 34.14% 78.69% 7/10
**PDC 1992-A 14.97% 12.83% 27.79% 31.58% 59.37% 7/5
**PDC 1992-B 46.15% 29.41% 75.56% 36.46% 112.02% 7/3
**PDC 1992-C 55.83% 26.71% 82.54% 37.49% 120.03% 7/0
**PDC 1993-A 87.59% 4.22% 91.82% 41.00% 132.82% 6/10
**PDC 1993-B 31.14% -- 31.14% 37.75% 68.90% 6/5
**PDC 1993-C 24.37% -- 24.37% 37.22% 61.60% 6/2
**PDC 1993-D 32.05% -- 32.05% 36.42% 68.48% 6/0
**PDC 1993-E 36.99% -- 36.99% 37.43% 74.42% 5/9
**PDC 1994-A 20.90% -- 20.90% 40.38% 61.28% 5/5
**PDC 1994-B 31.10% -- 31.10% 41.89% 72.99% 5/2
**PDC 1994-C 25.72% -- 25.72% 41.51% 67.24% 5/0
**PDC 1994-D 26.44% -- 26.44% 41.92% 68.36% 4/10
**PDC 1995-A 31.40% -- 31.40% 42.72% 74.12% 4/6
**PDC 1995-B 16.92% -- 16.92% 41.26% 58.19% 4/3
**PDC 1995-C 16.62% -- 16.62% 41.33% 57.95% 4/0
**PDC 1995-D 20.92% -- 20.92% 41.43% 62.35% 3/10
**PDC 1996-A 37.66% -- 37.66% 42.21% 79.87% 3/5
**PDC 1996-B 25.06% -- 25.06% 41.23% 66.29% 3/1
**PDC 1996-C 18.30% -- 18.30% 40.92% 59.21% 2/11
**PDC 1996-D 16.07% -- 16.07% 40.78% 56.84% 2/10
**PDC 1997-A 15.60% -- 15.60% 40.21% 55.81% 2/5
**PDC 1997-B 11.53% -- 11.53% 40.18% 51.70% 2/1
**PDC 1997-C 12.73% -- 12.73% 40.63% 53.36% 1/11
**PDC 1997-D 5.97% -- 5.97% 40.03% 46.00% 1/9
**PDC 1998-A 8.50% -- 8.50% 40.14% 48.65% 1/4
**PDC 1998-B 8.11% -- 8.11% 40.31% 48.42% 1/1
- 104 -
<PAGE>
**PDC 1998-C 6.33% -- 6.33% 40.03% 46.36% 0/11
**PDC 1998-D 3.37% -- 3.37% 39.59% 42.96% 0/9
**PDC 1999-A 2.74% -- 2.74% 39.21% 41.95% 0/5
**PDC 1999-B 1.84% -- 1.84% 39.09% 40.93% 0/1
**PDC 1999-C(6) 0.00% -- 0.00% 39.02% 39.02% 0/0
**PDC 1999-D(7) 0.00% -- 0.00% 39.02% 39.02% 0/0
</TABLE>
* 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 November 1999; wells were drilled during the
fourth quarter of 1999 and the first quarter of 2000; first revenue
distribution commenced in May, 2000.
(7) Partnership funded in December 1999; wells were drilled in the
fourth and the first quarter 2000; first revenue distribution to
commence in July, 2000.
INVESTOR SHOULD NOT CONSIDER OPERATING RESULTS OBTAINED BY THESE PRIOR
PARTNERSHIPS AS INDICATIVE OF THE OPERATING RESULTS OBTAINABLE BY THE
PARTNERSHIPS.
- 105 -
Partnership Estimated 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 estimated proved reserves
and future net reserves as of January 1, 2000. 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, 2000(1)
Estimated Estimated
Percent
Net Oil BBL Net Gas Estimated
Value
Category of Reserves Reserves Future Net
at 10% Per
Partnership Proved Reserves BBL MCF Revnues
Annum
PDC 1989-A(2).....Proved Developed 74,289 699,530 $2,512,336
$919,538
Proved Undeveloped -
-
Totals 74,289 699,530 $2,512,336
$919,538
PDC 1989-B(2).....Proved Developed - 868,746 $1,088,606
$494,607
Proved Undeveloped - -
--
Totals - 868,746 $1,088,606
$494,607
PDC 1990-A(2).....Proved Developed - 185,298 $166,338
$101,476
Proved Undeveloped - -
--
Totals - 185,298 $166,338
$101,476
PDC 1990-B(2).....Proved Developed - 908,911 $1,527,737
$427,844
Proved Undeveloped - -
--
Totals - 908,911 $1,527,737
$427,844
PDC 1990-C(2).....Proved Developed - 1,352,069 $2,138,263
$882,260
Proved Undeveloped - -
--
Totals - 1,352,069 $2,138,263
$882,260
PDC 1990-D(2).....Proved Developed - 1,852,164 $3,028,473
$941,893
Proved Undeveloped - -
--
Totals - 1,852,164 $3,028,473
$941,893
PDC 1991-A(2).....Proved Developed - 1,076,916 $1,591,994
$514,817
Proved Undeveloped - -
--
Totals - 1,076,916 $1,591,994
$514,817
PDC 1991-B(2).....Proved Developed - 808,269 $1,404,561
$583,489
Proved Undeveloped - -
--
Totals - 808,269 $1,404,561
$583,489
PDC 1991-C(2).....Proved Developed - 1,261,450 $1,909,232
$657,947
Proved Undeveloped - -
--
Totals - 1,261,450 $1,909,232
$657,947
PDC 1991-D(2).....Proved Developed - 1,537,323 $2,284,487
$977,741
Proved Undeveloped - -
--
Totals - 1,537,323 $2,284,487
$977,741
- 106 -
PDC 1992-A(2).....Proved Developed - 240,538 $253,254
$153,330
Proved Undeveloped - -
--
Totals - 240,538 $253,254
$153,330
PDC 1992-B(2).....Proved Developed - 2,014,676 $3,225,125
$1,099,980
Proved Undeveloped - -
--
Totals - 2,014,676 $3,225,125
$1,099,980
PDC 1992-C(2).....Proved Developed - 3,520,851 $5,857,807
$2,603,934
Proved Undeveloped - -
--
Totals - 3,520,851 $5,857,807
$2,603,934
PDC 1993-A(2).....Proved Developed - 1,641,727 $2,576,724
$883,285
Proved Undeveloped - -
--
Totals - 1,641,727 $2,576,724
$883,285
PDC 1993-B(2).....Proved Developed - 1,134,522 $1,793,194
$647,173
Proved Undeveloped - -
--
Totals - 1,134,522 $1,793,194
$647,173
PDC 1993-C(2).....Proved Developed - 1,884,169 $3,326,479
$1,050,325
Proved Undeveloped - -
--
Totals - 1,884,169 $3,326,479
$1,050,325
PDC 1993-D(2).....Proved Developed - 1,465,134 $2,518,505
$803,682
Proved Undeveloped - -
--
Totals - 1,465,134 $2,518,505
$803,682
PDC 1993-E(2).....Proved Developed 3,097 3,973,279 $6,955,078
$2,182,565
Proved Undeveloped - -
-
Totals 3,097 3,973,279 $6,955,078
$2,182,565
PDC 1994-A(2).....Proved Developed - 906,022 $1,394,953
$430,224
Proved Undeveloped - -
--
Totals - 906,022 $1,394,953
$430,224
PDC 1994-B(2).....Proved Developed - 1,248,766 $2,100,211
$858,829
Proved Undeveloped - -
--
Totals - 1,248,766 $2,100,211
$858,829
PDC 1994-C(2).....Proved Developed - 1,204,411 $2,015,723
$714,428
Proved Undeveloped - -
--
Totals - 1,204,411 $2,015,723
$714,428
PDC 1994-D(2).....Proved Developed - 3,259,918 $5,415,330
$2,266,064
Proved Undeveloped - -
--
Totals - 3,259,918 $5,415,330
$2,266,064
PDC 1995-A(2).....Proved Developed - 711,605 $975,223
$494,330
Proved Undeveloped - -
--
Totals - 711,605 $975,223
$494,330
PDC 1995-B(2).....Proved Developed - 530,656 $856,146
$307,080
Proved Undeveloped - -
--
Totals - 530,656 $856,146
$307,080
PDC 1995-C(2).....Proved Developed - 650,795 $783,295
$366,655
Proved Undeveloped - -
--
Totals - 650,795 $783,295
$366,655
- 107 -
PDC 1995-D(2).....Proved Developed - 2,134,423 $2,866,463
$1,549,272
Proved Undeveloped - -
--
Totals - 2,134,423 $2,866,463
$1,549,272
PDC 1996-A(2).....Proved Developed - 1,087,960 $1,886,496
$971,911
Proved Undeveloped - -
--
Totals - 1,087,960 $1,886,496
$971,911
PDC 1996-B(2).....Proved Developed - 901,311 $1,184,975
$684,284
Proved Undeveloped - -
--
Totals - 901,311 $1,184,975
$684,284
PDC 1996-C(2).....Proved Developed - 1,184,745 $1,621,370
$855,348
Proved Undeveloped - -
--
Totals - 1,184,745 $1,621,370
$855,348
PDC 1996-D(2).....Proved Developed - 4,978,478 $6,681,857
$3,604,734
Proved Undeveloped - -
--
Totals - 4,978,478 $6,681,857
$3,604,734
PDC 1997-A(2).....Proved Developed - 829,406 $1,188,850
$672,483
Proved Undeveloped - -
--
Totals - 829,406 $1,188,850
$672,483
PDC 1997-B(2).....Proved Developed - 1,439,718 $1,909,143
$1,139,079
Proved Undeveloped - -
--
Totals - 1,439,718 $1,909,143
$1,139,079
PDC 1997-C(2).....Proved Developed - 2,829,964 $4,579,592
$2,345,974
Proved Undeveloped - -
--
Totals - 2,829,964 $4,579,592
$2,345,974
PDC 1997-D(3).....Proved Developed - 6,313,050 $10,799,608
$5,269,317
Proved Undeveloped - -
--
Totals - 6,313,050 $10,799,608
$5,269,317
PDC 1998-A(3).....Proved Developed - 3,528,019 $5,401,068
$3,216,135
Proved Undeveloped - -
--
Totals - 3,528,019 $5,401,068
$3,216,135
PDC 1998-B(3).....Proved Developed - 6,359,734 $10,329,354
$5,958,968
Proved Undeveloped - -
--
Totals - 6,359,734 $10,329,354
$5,958,968
PDC 1998-C(3).....Proved Developed - 5,603,611 $8,165,363
$5,106,221
Proved Undeveloped - -
--
Totals - 5,603,611 $8,165,363
$5,106,221
PDC 1998-D(3).....Proved Developed - 9,050,807 15,674,942
$8,638,087
Proved Undeveloped - -
--
Totals - 9,050,807 15,674,942
$8,638,087
PDC 1999-A(3).....Proved Developed - 3,769,217 7,514,392
$3,680,417
Proved Undeveloped - -
--
Totals - 3,769,217 7,514,392
$3,680,417
PDC 1999-B(3).....Proved Developed 35,916 5,056,558 10,253,444
$5,319,900
Proved Undeveloped - -
--
Totals 35,916 5,056,558 10,253,444
$5,319,900
-108-
PDC 1999-C(3).....Proved Developed 36,650 3,147,846 6,925,986
$3,823,823
Proved Undeveloped - -
--
Totals 36,650 3,147,846 6,925,986
$3,823,823
PDC 1999-D(4).....Proved Developed - - -
-
Proved Undeveloped - -
--
Totals - - -
-
</TABLE>
____________________
(1) For the Partnerships PDC 1989-A through PDC 1992-C and from 1994-A
through 1999-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 engineer,
Wright & Company, Inc.
(4) The wells of this Partnership were drilled after December 31, 1999;
therefore, a reserve study has not been conducted.
INVESTORS SHOULD NOT CONSIDER OPERATING RESULTS OBTAINED BY THESE PRIOR
PARTNERSHIPS AS INDICATIVE OF THE OPERATING RESULTS OBTAINABLE BY THE
PARTNERSHIPS.
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TAX CONSIDERATIONS
The 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.
The following statements are based upon the provisions of the
Internal Revenue Code of 1986, as amended (the "Code"), 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 DISCUSSION OF THESE MATTERS SET FORTH
IN THE 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 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 his or her Partnership interest will
limit the deductibility of losses generated from the Partnership. See
"Basis and At Risk Limitations."
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5. An additional General Partner's interest will not be
considered a passive activity within the meaning of Code Section 469 and
losses generated while such general partner interest is so held will not
be limited by the passive activity provisions. See "Passive Loss and
Credit Limitations."
6. A Limited Partner's interest (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."
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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, 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 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.
-112-
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 it does not believe any
market will ever exist for the sale of Units and the Managing General
Partner will not make a market for the Units and that it will not make a
market for the Units. Further, the Units will not be traded on an
established securities market.
11. The Partnership 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
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
-113-
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.
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 1998 (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").
-114-
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 31, 2001Certain other requirements must also be
met. Although PDC will attempt to satisfy each requirement of the
Service and judicial authority for deductibility of IDC 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 2001 for
Partnerships designated "PDC 2000_- Limited Partnership") are not
deductible in whole or in part until 2001 for Partnerships
designated "PDC 2000- _ Limited Partnership"). Further, to the extent
drilling of the Partnership's wells does not commence by March 31,
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.
Treasury regulations provide that recapture is determined at the partner
level (subject to certain anti-abuse provisions). Where only a portion
of recapture property is disposed of, any IDC related to the entire
property is recaptured to the extent of the gain realized on the portion
of the property sold. In the case of the disposition of an undivided
interest in a property (as opposed to the disposition of a portion of the
property), a proportionate part of the IDC with respect to the property is
treated as allocable to the transferred undivided interest to the extent
of any realized gain.
Depletion Deductions
- Investors who are "independent producers" of oil and gas will
be entitled to claim a percentage depletion deduction on their
oil and gas income. In 2000 the deduction is 19% of
gross income not to exceed 64% of the taxpayer's taxable
income (subject to certain adjustments for wells producing 90
Mcf per day or 15 barrels of oil per day). After 1999 the
depletion rate may change but not below a minimum rate of 15%,
and the amount of depletion which may be claimed for a
property will be limited to 100% of the taxable income
(excluding depletion) from that property. Wells producing
over 90 Mcf per day or 15 barrels of oil per day will be a
percentage depletion deduction of 15% of the gross income.
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 than 5,000 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 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.
-115-
Percentage depletion is a statutory allowance pursuant to which a
deduction equal to a percentage of the taxpayer's gross income from each
property is allowed in any taxable year, 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 allowable deduction is limited to 100% of net
income on a property by property basis, and further limited to 65% of the
taxpayer's taxable income. In the case of "stripper well property," as
that term defined in Code Section 613A(c)(6)(D), the 100% of taxable
income limitation has been eliminated for taxable years 1998 to
2001. Code Section 613A(c)(6)(H). It is anticipated that some
of the properties of the Partnerships will likely constitute "stripper
well properties" for this purpose. The percentage depletion deduction rate
will vary with the price of oil, but the rate will not be less than 15%.
For 2000 the rate is 19%. 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.
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.
-116-
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.
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.
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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.
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.
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Notwithstanding this general rule, however, the economic performance
rules are applied in a different manner from that described above in
"Intangible Drilling and Development Costs Deductions." Economic
performance under the passive loss rules is defined as economic
performance, without regard to the spudding rule. Accordingly, if an
Additional General Partner's interest is converted to that of a limited
partner after the end of the year in which economic performance is deemed
to occur, but prior to the spudding date, any post-conversion losses will
be passive, notwithstanding the availability of such losses in a year in
which the taxpayer held the interest in an entity that did not limit his
liability. The "spudding rule" and "spudding date" refer to the date that
drilling commences.
If an Additional General Partner converts his interest to a Limited
Partner interest pursuant to the terms of the Partnership Agreement, the
character of a subsequently generated tax attribute will be dependent
upon, among other things, the nature of the tax attribute and whether
there arose, prior to conversion, losses to which the working interest
exception applied.
Accordingly, any loss arising therefrom should be treated as a PAL
with the benefits thereof limited as described above. However, if a
taxpayer has any loss from any taxable year from a working interest in
any oil or gas property that is treated as a non-passive loss, then any
net income from such property for any succeeding taxable year is to be
treated as income that is not from a passive activity. Consequently,
assuming that a converting Additional General Partner has losses from
working interests which are treated as non-passive, income from the
Partnership allocable to the Partner after conversion would be treated as
income that is not from a passive activity.
C. Limited Partner Interests
- Income and losses of Limited Partners will be treated as
"passive" for federal tax purposes.
If an Investor Partner invests in the Partnership as a Limited
Partner, his distributive share of the Partnership's losses will be
treated as PALs, the availability of which will be limited to the
Partner's passive income. If the Partner does not have sufficient passive
income to utilize the PAL, the disallowed PAL will be suspended and may be
carried forward to be deducted against passive income arising in future
years. Further, upon the disposition of the interest to an unrelated
party, in a fully taxable transaction such suspended losses will be
available, as described above.
Limited Partners should generally be entitled to offset their
distributive shares of passive income from the Partnerships with
deductions from other passive activities.
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.
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Tax benefits associated with oil and gas exploration activities
similar to that of the Program have been subject to the AMT in the past.
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.
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 10% 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.
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Partnership Distributions
Under the Code, any increase in a partner's share of partnership
liabilities, or any increase in such partner's individual liabilities by
reason of an assumption by him of partnership liabilities is considered to
be a contribution of money by the partner to the partnership. Similarly,
any decrease in a partner's share of partnership liabilities or any
decrease in such partner's individual liabilities by reason of the
partnership's assumption of such individual liabilities will be considered
as a distribution of money to the partner by the partnership.
The Partners' adjusted bases in their Units will initially consist
of the cash they contribute to the Partnership. Their bases will be
increased by their share of Partnership income and additional
contributions and decreased by their share of Partnership losses and
distributions. To the extent that such actual or constructive
distributions are in excess of a Partner's adjusted basis in his
Partnership interest (after adjustment for contributions and his share of
income and losses of the Partnership), that excess will generally be
treated as gain from the sale of a capital asset. In addition, gain could
be recognized to a distributee partner upon the disproportionate
distribution to a partner of unrealized receivables or substantially
appreciated inventory. The Partnership Agreement prohibits distributions
to any Investor Partner to the extent such would create or increase a
deficit in the Partner's Capital Account.
Partnership Allocations
The Partners' distributive shares of partnership income, gain, loss,
and deduction should be determined and allocated substantially in
accordance with the terms of the Partnership Agreement.
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).
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.
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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 not 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.
SUMMARY OF PARTNERSHIP AGREEMENT
The Limited Partnership Agreement (the "Partnership Agreement") in
the form attached to this Prospectus as Appendix A will govern the rights
and obligations of the Partners. 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.
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Liabilities of General Partners, Including Additional General Partners
General Partners, including Additional General Partners, will have
unlimited 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 may not 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 or her
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 or her breach of the Partnership Agreement. Section
7.01. Additional General Partners who choose to assign their Units in the
future may do so only 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 West Virginia Uniform Limited Partnership Act will govern the
Partnerships under which law a Limited Partner's liability for the
obligations of the partnership is limited to his or her Capital
Contribution, his or her share of Partnership assets and the return of any
part of his or her 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
or her rights and powers as a Limited Partner, such person takes part in
the control of the business of the Partnership. Section 7.01.
Allocations and Distributions
General: Profits and losses are to be allocated and cash is to be
distributed in the manner described in the section entitled "Participation
in Costs and Revenues." See Article III of the Partnership Agreement.
Time of Distributions: The Managing General Partner will determine
and distribute not less frequently than quarterly cash available for
distribution. 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
or her 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.
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Investor Partners may 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 in the Partnership Agreement, at
any meeting of Investor Partners, approval of any matters considered at
the meeting requires a vote of a majority of Units represented at such
meeting, in person or by proxy, at the meeting at which a quorum is
present. Approval of any of the following matters requires a vote of a
majority of the then outstanding Units entitled to vote:
(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. The
Managing General Partner if it were removed by the Investor Partners may
elect to retain its interest in the Partnership as a Limited Partner in
the 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 may 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 may 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 may 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;
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(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.
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, or other respective state securities
division with respect to the issue of indemnification for securities laws
violations.
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The Partnership will not incur the cost of the portion of any
insurance which insures any party against any liability as to which such
party is herein prohibited from being indemnified. Section 6.04.
Reports to Partners
The Managing General Partner will furnish to the Investor Partners
of each Partnership certain semi-annual and annual reports which will
contain financial statements (including a balance sheet and statements of
income, Partners' equity and cash flows), which statements at fiscal year
end will be audited by an independent accounting firm and will include a
reconciliation of such statements with information provided to the
Investor Partners for Federal income tax purposes. Financial statements
furnished in a Partnership's semi-annual reports will not be audited.
Semi-annually, all Investor Partners will also receive a summary
itemization of the transactions between the Managing General Partner or
any Affiliate thereof and the Partnership showing all items of
compensation received by the Managing General Partner and its Affiliates.
Annually beginning with the fiscal year ended December 31, 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." We direct the attention of prospective
investors to these sections.
TRANSFERABILITY OF UNITS
- The sale of Units by investors is limited; no market for the
Units will develop.
- Purchasers of Units from investors must satisfy the
suitability requirements of this offering and as imposed by
law.
No market for the Units will develop. An investor should consider
an investment in the Partnerships 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.
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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 or her entire fractional interest must be transferred.
Investors may assign Units 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
need not 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."
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.
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We are offering for sale units of preformation limited and general
partnership interest 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." We will not sell units
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 for the sale of the maximum number of 1,250 Units ($157,500
for the sale of the minimum number of 75 Units), 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
10.5% 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). 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 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.
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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), a sheet
presenting information regarding comparative investment deductions
("Investment Deductions") and a web site at www pdcgas.com. 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.
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, 1999 and 1998, included herein
and in the Registration Statement have been included herein and in the
Registration Statement in reliance upon the report of KPMG LLP,
independent auditors, 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. Reference is made to such Registration Statement, including
exhibits for further information. 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). We hereby make reference to
the copy of documents filed as exhibits to the Registration Statement for
full statements of the provisions thereof, and we qualify each such
statement in this Prospectus in all respects by this reference. You may
obtain copies of any materials filed as a part of the Registration
Statement from the Securities and Exchange Commission by payment of the
requisite fees therefor or you may examined these documents 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.
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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.
Assessment: Additional amounts of capital which may be mandatorily
required of or paid voluntarily by an Investor Partner beyond his
Subscription commitment.
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
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to the property cost in conformity with generally accepted accounting
principles and industry standards, except for expenses in connection with
the past drilling of wells which are not producers of sufficient
quantities of oil or gas to make commercially reasonable their continued
operations, and provided that the expenses enumerated in this subsection
(d) hereof shall have been incurred not more than 36 months prior to the
purchase by the Partnership; provided that such period may be extended, at
the discretion of the state securities administrator, upon proper
justification. When used with respect to services, "cost" means the
reasonable, necessary and actual expense incurred by the seller on behalf
of the Partnership in providing such services, determined in accordance
with generally accepted accounting principles. As used elsewhere, "cost"
means the price paid by the seller in an arm's-length transaction.
Dealer Manager: PDC Securities Incorporated, an affiliate of the Managing
General Partner.
Development Well: A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
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: Chase Manhattan Trust Company ,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.
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Independent Expert: A person with no material relationship to the
Managing General Partner who is qualified and who is in the business of
rendering opinions regarding the value of oil and gas properties based
upon the evaluation of all pertinent economic, financial, geologic and
engineering information available to the Managing General Partner.
Initial Limited Partner: Steven R. Williams or any successor to his
interest.
Investor Partner: Any investor participating in the Partnership as an
Additional General Partner or a Limited Partner, but excluding the
Managing General Partner and Initial Limited Partner.
Landowners' Royalty Interest: An interest in production, or the proceeds
therefrom, to be received free and clear of all costs of development,
operation, or maintenance, reserved by a landowner upon the creation of an
oil and gas lease.
Lease: Full or partial interests in: (i) undeveloped oil and gas leases;
(ii) oil and gas mineral rights; (iii) licenses; (iv) concessions; (v)
contracts; (vi) fee rights; or (vii) other rights authorizing the owner
thereof to drill for, reduce to possession and produce oil and gas.
Limited Partners: Those Investor Partners who purchase Units as Limited
Partners, transferees or assignees who become Limited Partners, or
Additional General Partners 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 29, 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.
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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 1998-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 for 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
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.
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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
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
-135-
(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.
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.
-136-
Petroleum Development Corporation and Subsidiaries
Consolidated Balance Sheets
December 31, 1999 and 1998
(With Independent Auditor's Report Thereon)
F-1
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, 1999 and 1998.
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 the 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 financial statement presentation. We believe that
our audits 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, 1999 and 1998,
in conformity with generally accepted accounting principles.
/s/KPMG LLP
Pittsburgh, Pennsylvania
March 6, 2000
F-2
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 1999 and 1998
<TABLE>
<C> <C> <C>
1999 1998
Assets
Current assets:
Cash and cash equivalents (includes
restricted cash of $614,300 and
$156,200, respectively) $29,059,200 34,894,600
Notes and accounts receivable 10,263,200 6,024,100
Inventories 577,600 702,400
Prepaid expenses 2,360,100 2,496,100
Total current assets 42,260,100 44,117,200
Properties and equipment:
Oil and gas properties (successful
efforts accounting method) 105,837,900 81,592,700
Pipelines 8,643,400 7,669,700
Transportation and other equipment 2,686,800 2,332,200
Land and buildings 1,181,000 1,152,700
118,349,100 92,747,300
Less accumulated depreciation,
depletion and amortization 31,207,300 27,356,700
87,141,800 65,390,600
Other assets 2,681,700 1,901,200
$132,083,600 111,409,000
</TABLE>
AN INVESTOR IN PDC 2000 DRILLING PROGRAM DOES NOT THEREBY ACQUIRE ANY
INTEREST IN THE ASSETS OF PETROLEUM DEVELOPMENT CORPORATION
(Continued)
F-3
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
December 31, 1999 and 1998
<TABLE>
<C> <C> <C>
1999 1998
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable $ 14,678,900 11,218,900
Accrued taxes 276,400 -
Other accrued expenses 2,643,700 1,959,900
Advances for future drilling contracts 25,137,400 28,320,800
Funds held for future distribution 2,027,600 984,200
Total current liabilities 44,764,000 42,483,800
Long-term debt 9,300,000 -
Other liabilities 3,160,600 2,233,500
Deferred income taxes 4,134,100 3,945,000
Commitments and contingencies
Stockholders' equity:
Common stock, par value $.01 per share;
authorized 50,000,000 shares; issued and
outstanding 15,737,795 and 15,510,762 157,400 155,100
Additional paid-in capital 32,071,000 31,873,100
Warrants outstanding - 46,300
Retained earnings 38,496,500 30,672,200
Total stockholders' equity 70,724,900 62,746,700
$132,083,600 111,409,000
</TABLE>
See accompanying notes to consolidated balance sheets.
AN INVESTOR IN PDC 2000 DRILLING PROGRAM DOES NOT THEREBY ACQUIRE ANY
INTEREST IN THE ASSETS OF PETROLEUM DEVELOPMENT CORPORATION
F-4
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
December 31, 1999 and 1998
(1) Summary of Significant Accounting Policies
Principles of Consolidation
The accompanying consolidated balance sheets include the accounts of
Petroleum Development Corporation and its wholly owned subsidiaries.
All material intercompany accounts and transactions have been
eliminated in consolidation. The Company accounts for its investment
in limited partnerships under the proportionate consolidation method.
Under this method, the Company's balance sheets include its prorata
share of assets and liabilities of the limited partnerships in which
it participates.
The Company is involved in three business segments. The segments are
drilling and development, natural gas sales and well operations. (See
Note 14)
The Company grants credit to purchasers of oil and gas and the owners
of managed properties, substantially all of whom are located in West
Virginia, Tennessee, Pennsylvania, Ohio, Michigan and Colorado.
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 in each year's calculation for measurement
purposes and expected costs are held constant throughout the
estimated life of the properties. 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.
(Continued)
F-5
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets (Continued)
December 31, 1999 and 1998
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.
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 restor-
ation, 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 not 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.
(Continued)
F-6
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets (Continued)
December 31, 1999 and 1998
Advances for Future Drilling Contracts
Represents funds received from Partnerships and other joint ventures
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.
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.
The Company has a deferred compensation arrangement covering executive
officers of the Company as a supplemental retirement benefit.
The Company has 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.
Revenue Recognition
Oil and gas wells are drilled primarily on a contract basis. The
Company follows the percentage-of-completion method of income
recognition for drilling operations in progress.
Income Taxes
Deferred tax assets and liabilities are recognized for the future tax
consequences attributable to differences between the balance sheets
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 and
option 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.
(Continued)
F-7
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets (Continued)
December 31, 1999 and 1998
Stock Compensation
The Company has 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. See
note 5 to the balance sheets.
Use of Estimates
Management of the Company has made a number of estimates and
assumptions relating to the reporting of assets and liabilities and
the disclosure of contingent assets and liabilities to prepare these
balance sheets in conformity with generally accepted accounting
principles. Actual results could differ from those estimates.
Estimates which are particularly significant to the consolidated
balance sheets include estimates of oil and gas reserves and future
cash flows from oil and gas properties.
Fair Value of Financial Instruments
The carrying values and fair values of the Company's receivables,
payables and debt obligations are estimated to be substantially the
same as of December 31, 1999 and 1998.
New Accounting Standards
Statement of Accounting Standards No. 133, Accounting for Derivative
Instruments and Hedging Activities (SFAS No. 133), was issued by the
Financial Accounting Standards Board in June, 1998. SFAS No. 133
standardized the accounting for derivative instruments, including
certain derivative instruments embedded in other contracts. SFAS No.
133 is effective for years beginning after June 15, 2000; however,
early adoption is permitted. On adoption, the provisions of SFAS No.
133 must be applied prospectively. At the present time, the Company
cannot determine the impact that SFAS No. 133 will have on its balance
sheets upon adoption, as such impact will be based on the extent of
derivative instruments, such as natural gas futures and option
contracts, outstanding at the date of adoption.
(2) Notes and Accounts Receivable
Included in other assets are noncurrent notes and accounts receivable
as of December 31, 1999 and 1998, in the amounts of $494,000 and
$617,900 net of the allowance for doubtful accounts of $216,900 and
$129,800, respectively.
The allowance for doubtful current accounts receivable as of December
31, 1999 and 1998 was $221,500 and $144,800, respectively.
(Continued)
F-8
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
December 31, 1999 and 1998
(3) Long-Term Debt
On June 22, 1999 the Company executed an Amendment to its Credit
Agreement with First National Bank of Chicago. The amendment
provides a $20.0 million borrowing base, subject to adequate oil and
gas reserves. The Company has activated $10.0 million of such
borrowing base, and has at its discretion the ability to activate the
additional $10.0 million. The Company is required to pay a
commitment fee of 1/4 percent on the unused portion of the activated
credit facility. Interest accrues at prime, with LIBOR (London
Interbank Market Rate) alternatives available at the discretion of
the Company. No principal payments are required until the credit
agreement expires on December 31, 2002.
As of December 31, 1999 the outstanding balance was $9,300,000 of which
$6,300,000 is at a prime rate of 8.5% and $3,000,000 at a LIBOR rate
of 7.73%. At December 31, 1998 there was no balance outstanding. Any
amounts outstanding under the credit agreement are 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.
(4) Income Taxes
The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and deferred tax liabilities at
December 31, 1999 and 1998 are presented below:
<TABLE>
<C> <C> <C>
1999 1998
Deferred tax assets:
Allowance for doubtful accounts $ 175,400 108,600
Drilling notes 105,700 109,200
Alternative minimum tax credit
carryforwards (Section 29) 1,982,300 1,783,000
Future abandonment 273,100 -
Deferred compensation 1,213,800 968,500
Other 51,600 148,300
Total gross deferred tax assets 3,801,900 3,117,600
Less valuation allowance - (375,000)
Deferred tax assets 3,801,900 2,742,600
Less current deferred tax assets
(included in prepaid expenses) (1,007,600) (927,400)
Net non-current deferred
tax assets 2,794,300 1,815,200
Deferred tax liabilities:
Plant and equipment, principally
due to differences in
depreciation and amortization (6,928,400) (5,760,200)
Total gross deferred
tax liabilities (6,928,400) (5,760,200)
Net deferred tax liability $(4,134,100) (3,945,000)
</TABLE>
The net changes in the total valuation allowance were decreases of
$375,000, $473,200 and $782,300 for the years ended December 31, 1999,
1998 and 1997, respectively.
At December 31, 1999, the Company has alternative minimum tax credit
carryforwards (Section 29) of approximately $1,982,300 which are
available to reduce future federal regular income taxes over an
indefinite period.
(Continued)
F-9
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets (Continued)
December 31, 1999 and 1998
(5) Common Stock
Changes in capital during 1999 and 1998 are as follows:
<TABLE>
<C> <C> <C> <C> <C> <C>
<C>
Common stock
issued
Number Additional Warrants
of paid-in out- Retained
shares Amount capital standing earnings
Total
Balance December 31, 1997 15,245,758 $152,500 31,553,100 46,300 24,014,200
55,766,100
Issuance of common stock:
Exercise of employee
stock options 324,333 3,200 300,800 - -
304,000
Amortization of stock award - - 12,200 - -
12,200
Repurchase and cancellation
of treasury stock (59,329) (600) (303,400) - -
(304,000)
Income tax benefit from the
exercise of stock options - - 310,400 - -
310,400
Net income - - - - 6,658,000
6,658,000
Balance December 31, 1998 15,510,762 $155,100 31,873,100 46,300 30,672,200
62,746,700
Issuance of common stock:
Exercise of employee
stock options 324,333 3,200 300,800 - -
304,000
Amortization of stock award - - 12,200 - -
12,200
Repurchase and cancellation
of treasury stock (97,300) (900) (303,100) - -
(304,000)
Income tax benefit from the
exercise of stock options - - 141,700 - -
141,700
Warrants expired - - 46,300 (46,300) -
-
Net income - - - - 7,824,300
7,824,300
Balance December 31, 1999 15,737,795 $157,400 32,071,000 - 38,496,500
70,724,900
</TABLE>
Options
Options amounting to 145,000 and 20,000 shares were granted during 1999 and
1998, respectively, to certain employees and directors under the Company's
Stock Option Plans. These options were granted with an exercise price equal
to market value as of the date of grant and vest over a six month period for
the 1999 grant and a two year period for the 1998 grant. The outstanding
options expire from 2000 to 2009.
The estimated fair value of the options granted during 1999 and 1998 was
$2.44 and $3.92 per option, respectively. The fair value was estimated
using the Black-Scholes option pricing model with the following assumptions
for the 1999 and 1998 grant, respectively: risk-free interest rate of 5.1%
and 5.9% expected dividend yield of 0%, expected volatility of 61.3% and
58.0% and expected life of 7 years.
<TABLE>
<C> <C> <C> <C>
Average Range of
Number Exercise Exercise
of Shares Price Prices
Outstanding December 31, 1997 1,872,650 $2.10 .94 - 5.13
Granted 20,000 $6.13 6.13 - 6.13
Exercised (324,333) $0.94 .94 - .94
Expired - $ - . - .
Outstanding December 31, 1998 1,568,317 $2.39 .94 - 6.13
Granted 145,000 $3.75 3.75 - 3.75
Exercised (324,333) $0.94 .94 - .94
Expired - $ - -
Outstanding December 31, 1999 1,388,984 $2.87 .94 - 6.13
</TABLE>
(Continued)
F-10
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets (Continued)
December 31, 1999 and 1998
As of December 31, 1999, there were 723,984 options outstanding and
exercisable in the $.94 to $1.62 exercise price range which have a
weighted average remaining contractual life of 2.7 years and weighted
average exercise price of $1.05. Also as of December 31, 1999 there
were 665,000 options outstanding and exercisable at a $3.75 to $6.13
exercise price range having a weighted average remaining contractual
life of 7.9 years and weighted average exercise price of $4.86.
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.
(6) Employee Benefit Plans
During 1999, 1998 and 1997 the Company expensed and established a
liability for $90,000 each year under a deferred compensation
arrangement with the executive officers of the Company.
In 1995, a total of 90,000 restricted shares of the Company's common
stock were granted to certain employees and available to them upon
retirement. The market value of shares awarded was $101,300. This
amount was recorded as unamortized stock award. The unamortized stock
award is being amortized to expense over the employees' expected years
to retirement and amounted to $12,200, $12,200 and $12,300 in 1999,
1998 and 1997, respectively.
At December 31, 1999 and 1998, the Company has recorded as other assets
$300,000 and $240,000, 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.
(7) Transactions with Affiliates
As part of its duties as well operator, the Company received $24,002,500
in 1999 and $22,997,300 in 1998 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 $10,322,500 in 1999 and $9,621,700 in 1998 for those services.
During 1999 and 1998, the Company paid $31,600 and $30,000, respectively
to the Corporate Secretary's law firm for various legal services.
(8) 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.
(Continued)
F-11
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
December 31, 1999 and 1998
Substantially all of the Company's drilling programs contain a repurchase
provision where Investors may tender their partnership units for
repurchase at any time beginning with the third anniversary of the
first cash distribution. The provision provides that the Company is
obligated to purchase an aggregate of 10% of the initial subscriptions
per calendar year (at a minimum price of four times the most recent 12
months' cash distributions), only if such units are tendered, subject
to the Company's financial ability to do so. The maximum annual 10%
repurchase obligation, if tendered by the investors, is currently
approximately $759,000. The Company has adequate capital to meet this
obligation.
The Company is not party to any legal action that would materially affect
the Company's results of operations or financial condition.
(9) Acquisitions
On February 19, 1998, the Company offered to purchase from Investors
their units of investment in the Company's Drilling Programs formed
prior to 1993. The Company purchased approximately $2.3 million of
producing oil and gas properties in conjunction with this offer, which
expired on March 31, 1998. The Company utilized capital received from
its Public Stock Offering to fund this purchase.
On June 12, 1998 the Company purchased for $3.1 million a majority
interest in the assets of Pemco Gas, Inc., a Pennsylvania producing
company. The assets include 122 natural gas wells, 2,700 undeveloped
acres, gathering systems, natural gas compressors and other facilities.
The Company estimates that its interest includes 4.7 Bcf of natural gas
reserves. The Company utilized capital received from its Public Stock
Offering to fund this purchase.
On November 16, 1998, the Company purchased all of the working interest
in a 13 well Antrim Shale production unit and adjacent development
locations in Montmorency County, Michigan. The Company estimates that
the purchase includes approximately 4 Bcf of proved developed producing
reserves and 1.5 Bcf of proved undeveloped reserves, with an
acquisition cost of approximately $2.8 million. The Company utilized
capital received from its Public Stock Offering to fund this purchase.
On January 29, 1999, the Company offered to purchase from Investors their
units of investment in the Company's Drilling Programs formed prior to
1996. The Company purchased approximately $1.8 million of producing
oil and gas properties in conjunction with this offer, which expired on
March 31, 1999. The Company utilized capital received from its Public
Stock Offering to fund this purchase.
On December 15, 1999, the Company purchased all of the working interest
in 53 producing wells in the D-J Basin of Colorado. The Company
estimates that the purchase includes proved developed reserves of
approximately 3.6 Bcf of natural gas and 370,000 barrels of oil or
approximately 5.8 Bcf equivalent (Bcfe), along with another 3.0 Bcfe of
proved undeveloped reserves. Also included in the acquisition was 16.5
net development drilling locations. The total acquisition cost for the
wells and locations was $5.2 million. The company utilized part of its
existing line of credit to fund the transaction. The effective date of
the transaction was December 1, 1999.
(Continued)
F-12
<PAGE>
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
December 31, 1999 and 1998
(10) 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 and option contracts
traded on the New York Mercantile Exchange. The futures and option
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.
As of December 31, 1999 and 1998, the Company had futures contracts for
the purchase of $4,318,000 and $1,120,300 of natural gas,
respectively. 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 $350,500 at December 31, 1999 and $(105,400) at
December 31, 1998.
The Company is required to maintain margin deposits with brokers for
outstanding futures contracts. As of December 31, 1999 and 1998,
cash in the amount of $614,300 and $156,200 was on deposit.
(11) 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:
Years Ended December 31,
1999 1998
Property acquisition cost:
Proved undeveloped
properties $2,532,200 1,903,200
Producing properties 6,997,500 8,679,000
Development costs 17,168,000 14,902,500
$26,697,700 25,484,700
Property acquisition costs include costs incurred to purchase, lease or
otherwise acquire a property. 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.
(12) 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>
<C> <C> <C>
December 31,
1999 1998
Proved properties:
Tangible well equipment $ 62,996,900 46,722,500
Intangible drilling costs 36,270,300 28,379,200
Well equipment leased to others 4,063,600 4,063,600
Undeveloped properties 2,507,100 2,427,400
105,837,900 81,592,700
Less accumulated depreciation,
depletion and amortization 23,652,000 20,395,400
$ 82,185,900 61,197,300
</TABLE>
(Continued)
F-13
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
December 31, 1999 and 1998
(13) Net Proved Oil and Gas Reserves (Unaudited)
The proved reserves of oil and gas of the Company have been estimated
by an independent petroleum engineer, Wright & Company, Inc. at
December 31, 1999 and 1998. These reserves have been prepared in
compliance with the Securities and Exchange Commission rules based on
year end prices. 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>
<C> <C> <C>
Oil (BBLS)
1999 1998
Proved developed and
undeveloped reserves:
Beginning of year 29,000 45,000
Revisions of previous estimates 67,000 (10,000)
Beginning of year as revised 96,000 35,000
New discoveries and extensions 404,000 -
Dispositions - -
Acquisitions 662,000 2,000
Production (8,000) (8,000)
End of year 1,154,000 29,000
Proved developed reserves:
Beginning of year 29,000 45,000
End of year 798,000 29,000
Gas (MCF)
1999 1998
Proved developed and
undeveloped reserves:
Beginning of year 80,819,000 57,243,000
Revisions of previous estimates (4,475,000) (3,517,000)
Beginning of year as revised 76,344,000 53,726,000
New discoveries and extensions 24,781,000 23,552,000
Dispositions to partnerships (8,774,000) (6,009,000)
Acquisitions 12,345,000 12,003,000
Production (3,451,000) (2,453,000)
End of year 101,245,000 80,819,000
Proved developed reserves:
Beginning of year 64,562,000 42,411,000
End of year 82,628,000 64,562,000
</TABLE>
(14) 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.
(Continued)
F-14
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
December 31, 1999 and 1998
<TABLE>
<C> <C> <C>
Years Ended December 31,
1999 1998
Future estimated cash flows $307,816,000 186,598,000
Future estimated production
and development costs (129,557,000) (95,670,000)
Future estimated income
tax expense (39,930,000) (20,322,000)
Future net cash flows 138,329,000 70,606,000
10% annual discount for
estimated timing of cash
flows (79,875,000) (40,412,000)
Standardized measure of
discounted future
estimated net cash flows $ 58,454,000 30,194,000
The following table summarizes the principal sources of change in the
standardized measure of discounted future estimated net cash flows:
Years Ended December 31,
1999 1998
Sales of oil and gas
production, net of
production costs $(6,206,000) (4,605,000)
Net changes in prices
and production costs 29,547,000 (23,083,000)
Extensions, discoveries
and improved recovery,
less related cost 39,653,000 18,615,000
Dispositions to partnerships (6,152,000) (5,762,000)
Acquisitions 31,915,000 13,938,000
Development costs incurred
during the period 17,168,000 14,903,000
Revisions of previous
quantity estimates (4,944,000) (5,605,000)
Changes in estimated
income taxes (19,608,000) 459,000
Changes in discount (39,463,000) 1,224,000
Changes in production rates
(timing) and other (13,650,000) (7,826,000)
$ 28,260,000 2,258,000
</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.
(Continued)
F-15
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Notes to Consolidated Balance Sheets
December 31, 1999 and 1998
(15) Business Segments (Thousands)
PDC's operating activities can be divided into three major segments:
drilling and development, natural gas sales, and well operations. The
Company drills natural gas wells for Company-sponsored drilling partnerships
and retains an interest in each well. The Company also engages in oil and
gas sales to residential, commercial and industrial end-users. The Company
charges Company-sponsored partnerships and other third parties competitive
industry rates for well operations and gas gathering. Segment information
for the years ended December 31, 1999 and 1998 is as follows:
<TABLE>
<C> <C> <C>
1999 1998
SEGMENT ASSETS
Drilling and Development $23,957 27,288
Natural Gas Sales 93,073 65,256
Well Operations 7,977 7,136
Unallocated amounts
Cash 1,967 7,814
Other 4,934 3,806
Total $131,908 111,300
1999 1998
EXPENDITURES FOR SEGMENT
LONG-LIVED ASSETS
Drilling and Development $ 1,710 1,953
Natural Gas Sales 24,613 23,645
Well Operations 1,328 947
Unallocated amounts 107 85
Total $27,758 26,630
</TABLE>
F-16
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
March 31, 2000 and December 31, 1999
<TABLE>
<C> <C> <C>
ASSETS
2000 1999
(Unaudited)
Current assets:
Cash and cash equivalents $ 13,838,100 $ 29,059,200
Accounts and notes receivable 11,856,600 10,263,200
Inventories 364,700 577,600
Prepaid expenses 3,085,800 2,360,100
Total current assets 29,145,200 42,260,100
Properties and equipment 120,456,900 118,349,100
Less accumulated depreciation,
depletion and amortization 32,694,800 31,207,300
87,762,100 87,141,800
Other assets 2,505,800 2,681,700
$119,413,100 $132,083,600
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 18,322,400 $ 17,599,000
Advances for future drilling contracts 7,183,900 25,137,400
Funds held for future distribution 1,838,500 2,027,600
Total current liabilities 27,344,800 44,764,000
Long-term debt, excluding current maturities 10,000,000 9,300,000
Other liabilities 3,502,600 3,160,600
Deferred income taxes 4,382,300 4,134,100
Commitments and contingencies
Stockholders' equity:
Common stock 159,800 157,400
Additional paid-in capital 32,285,700 32,071,000
Retained earnings 41,737,900 38,496,500
Total stockholders' equity 74,183,400 70,724,900
$119,413,100 $132,083,600
</TABLE>
AN INVESTOR IN PDC 2000 DRILLING PROGRAM DOES NOT THEREBY ACQUIRE ANY INTEREST
IN THE ASSETS OF PETROLEUM DEVELOPMENT CORPORATION
F-17
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, 1999 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 March 31, 2000 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 March 31, 2000 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 March 31, 2000. There has
been no change in commitments and contingencies as described in Note 8 of the
Consolidated Balance Sheet at December 31, 1999.
AN INVESTOR IN PDC 2000 DRILLING PROGRAM DOES NOT THEREBY ACQUIRE ANY INTEREST
IN THE ASSETS OF PETROLEUM DEVELOPMENT CORPORATION
F-18
APPENDIX A
FORM OF
LIMITED PARTNERSHIP AGREEMENT
OF
PDC 1998-___ LIMITED PARTNERSHIP
[PDC 1999-___ LIMITED PARTNERSHIP]
[PDC 2000-___ LIMITED PARTNERSHIP]
TABLE OF CONTENTS
Page
ARTICLE I: The Partnership
1.01 Organization. . . . . . . . . . . . . . . . . . . 1
1.02 Partnership Name. . . . . . . . . . . . . . . . . 1
1.03 Character of Business . . . . . . . . . . . . . . 1
1.04 Principal Place of Business . . . . . . . . . . . 1
1.05 Term of Partnership . . . . . . . . . . . . . . . 2
1.06 Filings . . . . . . . . . . . . . . . . . . . . . 2
1.07 Independent Activities. . . . . . . . . . . . . . 2
1.08 Definitions . . . . . . . . . . . . . . . . . . . 3
ARTICLE II: Capitalization. . . . . . . . . . . . . . . . . . . . .12
2.01 Capital Contributions of the Managing General
Partner and Initial Limited Partner. . . . . . .12
2.02 Capital Contributions of the Investor
Partners. . . . . . . . . . . . . . . . . . . . .12
2.03 Additional Contributions. . . . . . . . . . . . .13
ARTICLE III: Capital Accounts and Allocations. . . . . . . . . . . .14
3.01 Capital Accounts. . . . . . . . . . . . . . . . .14
3.02 Allocation of Profits and Losses. . . . . . . . .16
3.03 Depletion . . . . . . . . . . . . . . . . . . . .22
3.04 Apportionment Among Partners. . . . . . . . . . .22
ARTICLE IV: Distributions . . . . . . . . . . . . . . . . . . . . .23
4.01 Time of Distribution. . . . . . . . . . . . . . .23
4.02 Distributions . . . . . . . . . . . . . . . . . .23
4.03 Capital Account Deficits. . . . . . . . . . . . .24
4.04 Liability Upon Receipt of Distributions . . . . .24
ARTICLE V: Activities. . . . . . . . . . . . . . . . . . . . . . .24
5.01 Management. . . . . . . . . . . . . . . . . . . .25
5.02 Conduct of Operations . . . . . . . . . . . . . .25
5.03 Acquisition and Sale of Leases. . . . . . . . . .27
5.04 Title to Leases . . . . . . . . . . . . . . . . .27
5.05 Farmouts. . . . . . . . . . . . . . . . . . . . .28
5.06 Release, Abandonment, and Sale or Exchange
of Properties . . . . . . . . . . . . . . . . . .28
5.07 Certain Transactions. . . . . . . . . . . . . . .29
ARTICLE VI: Managing General Partner. . . . . . . . . . . . . . . .33
6.01 Managing General Partner. . . . . . . . . . . . .33
6.02 Authority of Managing General
Partner . . . . . . . . . . . . . . . . . . . . .34
6.03 Certain Restrictions on Managing General
Partner's Power and Authority . . . . . . . . . .35
6.04 Indemnification of Managing General
Partner . . . . . . . . . . . . . . . . . . . . 37
6.05 Withdrawal. . . . . . . . . . . . . . . . . . . 38
6.06 Management Fee. . . . . . . . . . . . . . . . . .38
6.07 Tax Matters and Financial Reporting Partner . . .38
ARTICLE VII: Investor Partners . . . . . . . . . . . . . . . . . . .39
7.01 Management. . . . . . . . . . . . . . . . . . . .39
7.02 Indemnification of Additional
General Partners. . . . . . . . . . . . . . . . .39
7.03 Assignment of Units . . . . . . . . . . . . . . .40
7.04 Prohibited Transfers. . . . . . . . . . . . . . .41
7.05 Withdrawal by Investor Partners . . . . . . . . .42
7.06 Removal of Managing General Partner . . . . . . .42
7.07 Calling of Meetings . . . . . . . . . . . . . . 43
7.08 Additional Voting Rights. . . . . . . . . . . . .43
7.09 Voting by Proxy . . . . . . . . . . . . . . . . .43
7.10 Conversion of Additional General Partner
Interests into Limited Partner Interests. . . . .43
7.11 Unit Repurchase Program . . . . . . . . . . . . .44
7.12 Liability of Partners . . . . . . . . . . . . . .45
i
ARTICLE VIII: Books and Records . . . . . . . . . . . . . . . .46
8.01 Books and Records . . . . . . . . . . . . . . . .46
8.02 Reports . . . . . . . . . . . . . . . . . . . . .47
8.03 Bank Accounts . . . . . . . . . . . . . . . . . .49
8.04 Federal Income Tax Elections. . . . . . . . . . .49
ARTICLE IX: Dissolution; Winding-up . . . . . . . . . . . . . . . .49
9.01 Dissolution . . . . . . . . . . . . . . . . . . .49
9.02 Liquidation . . . . . . . . . . . . . . . . . . .50
9.03 Winding-up . . . . . . . . . . . . . . . . . . .50
ARTICLE X: Power of Attorney . . . . . . . . . . . . . . . . . . .51
10.01 Managing General Partner as Attorney-in-Fact. . .51
10.02 Nature of Special Power . . . . . . . . . . . . .52
ARTICLE XI: Miscellaneous Provisions . . . . . . . . . . . . . . .53
11.01 Liability of Parties . . . . . . . . . . . . . .53
11.02 Notices . . . . . . . . . . . . . . . . . . . . .53
11.03 Paragraph Headings . . . . . . . . . . . . . . .53
11.04 Severability . . . . . . . . . . . . . . . . . .53
11.05 Sole Agreement. . . . . . . . . . . . . . . . . .53
11.06 Applicable Law. . . . . . . . . . . . . . . . . .53
11.07 Execution in Counterparts . . . . . . . . . . . .53
11.08 Waiver of Action for Partition . . . . . . . . .53
11.09 Amendments . . . . . . . . . . . . . . . . . . .54
11.10 Consent to Allocations and Distributions. . . . .54
11.11 Ratification. . . . . . . . . . . . . . . . . . .54
11.12 Substitution of Signature Pages . . . . . . . . .55
11.13 Incorporation by Reference . . . . . . . . . . .55
Signature Page. . . . . . . . . . . . . . . . . .56
ii
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
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.
1
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:
(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.
2
(d) "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
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
3
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.
(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;
4
(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.
(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.
5
(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.
(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).
6
(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).
(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
7
different for different horizons, shall be designated by the Managing
General Partner in writing prior to the conduct of program operations and
shall be enlarged or contracted from time to time on the basis of
subsequently acquired information to define the anticipated limits of the
associated hydrocarbon reserves and to include all acreage encompassed
therein. A "prospect" with respect to a particular horizon may be limited
to the minimum area permitted by state law or local practice, whichever is
applicable, to protect against drainage from adjacent wells if the well to
be drilled by the Partnership is to a horizon containing proved reserves.
(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.
(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.
8
(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.
(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.
9
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.
(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.
10
(f) Until proceeds from the public offering are invested in
the Partnership's operations, such proceeds may be temporarily invested in
income producing short-term, highly liquid investments, where there is
appropriate safety of principal, such as U.S. Treasury Bills. Any such
income shall be allocated pro rata to the Investor Partners providing such
capital contributions.
2.03 Additional Contributions. Except as otherwise provided in
this Agreement, no Investor Partner shall be required or obligated (a) to
contribute any capital to the Partnership other than as provided in
Section 2.02 hereof, or (b) to lend any funds to the Partnership. No
interest shall be paid on any capital contributed to the Partnership
pursuant to this Article II and, except as otherwise provided herein, no
Partner, other than the Initial Limited Partner as authorized herein, may
withdraw his Capital Contribution. The Units are nonassessable; however,
General Partners are liable, in addition to their Capital Contributions,
for Partnership obligations and liabilities represented by their ownership
of interests as general partners, in accordance with West Virginia law.
ARTICLE III
Capital Accounts and Allocations
3.01 Capital Accounts.
(a) General. A separate Capital Account shall be
established and maintained for each Partner on the books and records of
the Partnership. Capital Accounts shall be maintained in accordance with
Treas. Reg. Section 1.704-1(b) and any inconsistency between the
provisions of this Section 3.01 and such regulation shall be resolved in
favor of the regulation. In the event the Managing General Partner shall
determine that it is prudent to modify the manner in which the Capital
Accounts, or any debits or credits thereto (including, without limitation,
debits or credits relating to liabilities that are secured by contributed
or distributed property or that are assumed by the Partnership of the
Partners), are computed in order to comply with such regulations, the
Managing General Partner may make such modification, provided that it is
not likely to have a material effect on the amounts distributable to any
Partner pursuant to Section 9.03 hereof upon the dissolution of the
Partnership. The Managing General Partner also shall (i) make any
adjustments that are necessary or appropriate to maintain equality between
the Capital Accounts of the Partners and the amount of Partnership capital
reflected on the Partnership's balance sheet, as computed for book
purposes, in accordance with Treas. Reg. Section 1.704-1(b)(2)(iv)(q), and
(ii) make any appropriate modifications in the event unanticipated events
might otherwise cause this Agreement not to comply with Treas. Reg.
Section 1.704-1(b).
(b) Increases to Capital Accounts. Each Partner's Capital
Account shall be credited with (i) the amount of money contributed by him
to the Partnership; (ii) the amount of any Partnership liabilities that
are assumed by him (within the meaning of Treas. Reg. Section 1.704-
1(b)(2)(iv)(c)), but not by increases in his share of Partnership
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
11
taxable income and not properly chargeable to Capital Account (as
described in Code Section 705(a)(2)(B)), and (v) allocations to him of
Partnership Losses (or item thereof), including loss and deduction
described in Treas. Reg. Section 1.704-1(b)(2)(iv)(g) (relating to
adjustments to reflect book value), but excluding items described in (iv)
above and excluding loss or deduction described in Treas. Reg. Section
1.704-1(b)(4)(iii) (relating to excess percentage depletion).
(d) Adjustments to Capital Accounts Related to Depletion.
(i) Solely for purposes of maintaining the
Capital Accounts, each year the Partnership shall
compute (in accordance with Treas. Reg. Section
1.704-1(b)(2)(iv)(k)) a simulated depletion allowance
for each oil and gas property using that method, as
between the cost depletion method and the percentage
depletion method (without regard to the limitations of
Code Section 613A(c)(3) which theoretically could apply
to any Partner), which results in the greatest simulated
depletion allowance. The simulated depletion allowance
with respect to each oil and gas property shall reduce
the Partners' Capital Accounts in the same proportion as
the Partners were allocated adjusted basis with respect
to such oil and gas property under Section 3.03(a)
hereof. In no event shall the Partnership's aggregate
simulated depletion allowance with respect to an oil and
gas property exceed the Partnership's adjusted basis in
the oil and gas property (maintained solely for Capital
Account purposes).
(ii) Upon the taxable disposition of an oil and
gas property by the Partnership, the Partnership shall
determine the simulated (hypothetical) gain or loss with
respect to such oil and gas property (solely for Capital
Account purposes) by subtracting the Partnership's
simulated adjusted basis for the oil and gas property
(maintained solely for Capital Account purposes) from
the amount realized by the Partnership upon such
disposition. Simulated adjusted basis shall be
determined by reducing the adjusted basis by the
aggregate simulated depletion charged to the Capital
Accounts of all Partners in accordance with Section
3.01(d)(i) hereof. The Capital Accounts of the Partners
shall be adjusted 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 during the
production phase 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:
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(i) IDC and recapture of IDC shall be allocated 100%
to the Investor Partners and 0% to the Managing General
Partner , except as otherwise provided in the following
clause; however, in the event that a portion of the Capital
Contribution of the Managing General Partner is utilized for
IDC, then IDC and recapture of IDC shall be allocated to the
Investor Partners and the Managing General Partner in a
percentage equal to their respective contribution to IDC;
(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;
(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.
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(iii) Qualified Income Offset. In the event any
Investor Partner unexpectedly receives any adjustments,
allocations, or distributions described in Treas. Reg. Section
1.704-1(b)(2)(ii)(d)(4), (5), or (6), items of Partnership
income and gain shall be specifically allocated to such
Partner in an amount and manner sufficient to eliminate (to
the extent required by the Regulations) the total of the
deficit balance in his Capital Account (as adjusted in Section
3.02(b)(i)) created by such adjustments, allocations, or
distributions, provided that an allocation pursuant to this
Section 3.02(b)(iii) shall be made if and only to the extent
that such Partner would have a deficit in his Capital Account
(as adjusted in Section 3.02(b)(i)) after all other
allocations provided for in this Section 3 have been
tentatively made as if this Section 3.02(b)(iii) were not in
the Agreement.
(iv) Gross Income Allocations. In the event an
Investor Partner has a deficit Capital Account at the end of
any Partnership fiscal year which is in excess of the sum of
(i) the amount such Partner is obligated to restore pursuant
to any provision of this Agreement and (ii) the amount such
Partner is deemed to be obligated to restore pursuant to the
penultimate sentences of Treas. Reg. Sections 1.704-2(g)(1)
and 1.704-2(i)(5), such Partner shall be specially allocated
items of Partnership income and gain in the amount of such
excess as quickly as possible, provided that an allocation
pursuant to this Section 3.02(b)(iv) shall be made only if and
to the extent that such Partner would have a deficit Capital
Account in excess of such sum after all other allocations
provided for in this Section 3 have been made as if Section
3.02(b)(iii) hereof and this Section 3.02(b)(iv) were not in
the Agreement.
(c) Minimum Gain Chargeback. Notwithstanding any other
provision of this Section 3.02, if there is a net decrease in Partnership
Minimum Gain during any taxable year, pursuant to Treas. Reg. Section
1.704-2(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 economic distortions
caused by such net decrease in Partnership Minimum Gain,
and (ii) allocations pursuant to this Section
3.02(h)(iii) shall be deferred with respect to
allocations pursuant to Section 3.02(e) hereof to the
extent the Managing General Partner reasonably
determines that such allocations are likely to be offset
by subsequent allocations pursuant to Section 3.02(c).
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(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:
(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
16
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.
(m) Tax Allocations: Code Section 704(c). In accordance
with Code Section 704(c) and the Regulations thereunder, income, gain,
loss, and deduction with respect to any property contributed to the
capital of the Partnership shall, solely for tax purposes, be allocated
among the Partners so as to take account of any variation between the
adjusted basis of such property to the Partnership for federal income tax
purposes and its initial Gross Asset Value (computed in accordance with
Section 1.08(r)(1).
In the event the Gross Asset Value of any Partnership asset is
adjusted pursuant to Section 1.08(r)(1) hereof, subsequent allocations of
income, gain, loss, and deduction with respect to such asset shall take
account of any variation between the adjusted basis of such asset for
federal income tax purposes and its Gross Asset Value in the same manner
as under Code Section 704(c) and the Regulations thereunder.
Any elections or other decisions relating to such allocations shall
be made by the Managing General Partner in any manner that reasonably
reflects the purpose and intention of this Agreement. Allocations
pursuant to this Section 3.02(m) are solely for purposes of federal,
state, and local taxes and shall not affect, or in any way be taken into
account in computing, any Person's Capital Account or share of Profits,
Losses, other items, or distributions pursuant to any provision of this
Agreement.
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3.03 Depletion.
(a) The depletion deduction with respect to each oil and gas
property of the Partnership shall be computed separately for each Partner
in accordance with Code Section 613A(c)(7)(D) for Federal income tax
purposes. For purposes of such computation, the adjusted basis of each
oil and gas property shall be allocated in accordance with the Partners'
interests in the capital of the Partnership. Among the Investor Partners,
such adjusted basis shall be apportioned among them in accordance with the
number of Units held.
(b) Upon the taxable disposition of an oil or gas property
by the Partnership, the amount realized from and the adjusted basis of
such property shall be allocated among the Partners (for purposes of
calculating their individual gain or loss on such disposition for Federal
income tax purposes) as follows:
(i) The portion of the total amount realized upon the
taxable disposition of such property that represents recovery
of its simulated adjusted tax basis therein (as calculated
pursuant to Section 3.01(d) hereof) shall be allocated to the
Partners in the same proportion as the aggregate adjusted
basis of such property was allocated to such Partners (or
their predecessors in interest) pursuant to Section 3.03(a)
hereof; and
(ii) The portion of the total amount realized upon the
taxable disposition of such property that represents the
excess over the simulated adjusted tax basis therein shall be
allocated in accordance with the provisions of Section 3.02
hereof as if such gain constituted an item of Profit.
3.04 Apportionment Among Partners:
(a) Except as otherwise provided in this Agreement, all
allocations and distributions to the Investor Partners shall be
apportioned among them pro rata based on Units held by the Partners.
(b) For purposes of Section 3.04(a) hereof, an Investor
Partner's pro rata share in Units shall be calculated as of the end of the
taxable year for which such allocation has been made; provided, however,
that if a transferee of a Unit is admitted as an Investor Partner during
the course of the taxable year, the apportionment of allocations and
distributions between the transferor and transferee of such Unit shall be
made in the manner provided in Section 3.04(c) hereof.
(c) If, during any taxable year of the Partnership, there is
a change in any Partner's interest in the Partnership, each Partner's
allocation of any item of income, gain, loss, deduction, or credit of the
Partnership for such taxable year, other than "allocable cash basis items"
shall be determined by taking into account the varying interests of the
Partners pursuant to such method as is permitted by Code Section 706(d)
and the regulations thereunder. Each Partner's share of "allocable cash
basis items" shall be determined in accordance with Code Section 706(d)(2)
by (i) assigning the appropriate portion of each item to each day in the
period to which it is attributable, and (ii) allocating the portion
assigned to any such day among the Partners in proportion to their
interests in the Partnership at the close of such day. "Allocable cash
basis item" shall have the meaning ascribed to it by Code Section
706(d)(2)(B) and the regulations thereunder.
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.
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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.
(ii) Average Annual Rate of Return for purposes of
this sharing arrangement shall be defined as (1) the sum of
cash distributions and estimated tax savings of 25% of
Subscriptions 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.
19
(c) A Partner receives a return of his Capital Contribution
to the extent that the distribution to him reduces his share of the fair
value of the net assets of the Partnership below the value, as set forth
in the records required to be kept by West Virginia law, of his Capital
Contribution which has not been distributed to him.
ARTICLE V
Activities
5.01 Management. The Managing General Partner shall conduct,
direct, and exercise full and exclusive control over all activities of the
Partnership. Investor Partners shall have no power over the conduct of
the affairs of the Partnership or otherwise commit or bind the Partnership
in any manner. The Managing General Partner shall manage the affairs of
the Partnership in a prudent and businesslike fashion and shall use its
best efforts to carry out the purposes and character of the business of
the Partnership.
5.02 Conduct of Operations.
(a)(i) The Managing General Partner shall establish a
program of operations for the Partnership which shall be in
conformance with the following policies: (x) no less than 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,
Colorado, New York, Kentucky, Michigan, Indiana, Kansas,
Montana, South Dakota, Tennessee, Utah, 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 20%.
(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
20
<PAGE>
inconsistent with this Partnership Agreement, shall be governed by the
AAPL Form 610 Model Operating Agreement-1982, with a provision reserving
the right to take production in-kind, naming the Managing General Partner
as operator and the Partnership as a nonoperator, and with the accounting
procedure to govern as the accounting procedures under such Operating
Agreements.
(e) The Managing General Partner is generally expected to
act as the operator of 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.
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
21
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.
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.
22
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.
(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
23
a proportionate Working Interest, the respective obligations of the
Managing General Partner or the Affiliate and the Partnership are
substantially the same after the sale of the interest to the Partnership,
and the Managing General Partner's or Affiliate's interest in revenues
does not exceed the amount proportionate to its Working Interest.
(e) Any services, equipment, or supplies which the Managing
General Partner or an Affiliate furnishes to the Partnership shall be
furnished at the lesser of the Managing General Partner's or the
Affiliate's Cost or a competitive rate which could be obtained in the
geographical area of operations unless the Managing General Partner or any
Affiliate is engaged to a substantial extent, as an ordinary and ongoing
business, in providing such services, equipment, or supplies to others in
the industry, in which event, the services, supplies, or equipment may be
provided by such person to the Partnership at prices competitive with
those charged by others in the geographical area of operations which would
be available to the Partnership. If such entity is not engaged in the
business as set forth above, then such compensation, price or rental shall
be the cost of such services, equipment or supplies to such entity, or the
competitive rate which could be obtained in the area, whichever is less.
Any drilling services provided by the Managing General Partner or its
Affiliates shall be billed only on a per foot, per day, or per hour rate,
or some combination thereof. No turnkey drilling contracts shall be made
between the Managing General Partner or its Affiliates and the
Partnership. Neither the Managing General Partner nor its Affiliates
shall profit by drilling in contravention of its fiduciary obligations to
the Partnership. Any such services for which the Managing General Partner
or an Affiliate is to receive compensation shall be embodied in a written
contract which precisely describes the services to be rendered and all
compensation to be paid.
(f) Advance payments by the Partnership to the Managing
General Partner are prohibited, except where necessary to secure tax
benefits of prepaid drilling costs.
(g) Neither the Managing General Partner nor its Affiliates
shall make any future commitments of the Partnership's production which
do not primarily benefit the Partnership, nor shall the Managing General
Partner or any Affiliate utilize Partnership funds as compensating
balances for the benefit of the Managing General Partner or the Affiliate.
(h) No rebates or give-ups may be received by the Managing
General Partner or any of its Affiliates, nor may the Managing General
Partner or any Affiliate participate in any reciprocal business
arrangements which would circumvent these restrictions.
(i) During a period of five years from the date of formation
of the Partnership, if the Managing General Partner or any of its
Affiliates proposes to acquire from an unaffiliated person an interest in
a Prospect in which the Partnership possesses an interest or in a Prospect
in which the Partnership's interest has been terminated without
compensation within one year preceding such proposed acquisition, the
following conditions shall apply:
(1) If the Managing General Partner or the Affiliate
does not currently own property in the Prospect separately
from the 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.
24
(j) If the Partnership acquires property pursuant to a
farmout or joint venture from an affiliated program, the Managing General
Partner's and/or its Affiliates' aggregate compensation associated with
the property and any direct and indirect ownership interest in the
property may not exceed the lower of the compensation and ownership
interest the Managing General Partner and/or its Affiliates could receive
if the property were separately owned or retained by either one of the
programs.
(k) Neither the Managing General Partner nor any Affiliate,
including affiliated programs, may purchase or acquire any property from
the Partnership, directly or indirectly, except pursuant to transactions
that are fair and reasonable to the Investor Partners of the Partnership
and then subject to the following conditions:
(1) A sale, transfer or conveyance, including a
farmout, of an undeveloped property from the Partnership to
the Managing General Partner or an Affiliate, other than an
affiliated program, must be made at the higher of cost or fair
market value.
(2) A sale, transfer or conveyance of a developed
property from the Partnership to the Managing General Partner
or an Affiliate, other than an affiliated program in which the
interest of the Managing General Partner is substantially
similar to or less than its interest in the subject
Partnership, shall not be permitted except in connection with
the liquidation of the Partnership and then only at fair
market value.
(3) Except in connection with farmouts or joint
ventures made in compliance with Section 5.07(j) above, a
transfer of an undeveloped property from the Partnership to an
affiliated drilling program must be made at fair market value
if the property has been held for more than two years.
Otherwise, if the Managing General Partner deems it to be in
the best interest of the Partnership, the transfer may be made
at cost.
(4) Except in connection with farmouts or joint
ventures made in compliance with Section 5.07(j) above, a
transfer of any type of property from the Partnership to an
affiliated production purchase or income program must be made
at fair market value if the property has been held for more
than six months or 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:
25
(1) An appraisal of all Partnership assets shall be
obtained from a competent independent expert. If the
appraisal will be included in a prospectus used to offer the
securities of a Roll-Up Entity, the appraisal shall be filed
with the Securities and Exchange Commission and the
Administrator as an exhibit to the registration statement for
the offering. The appraisal shall be based on all relevant
information, including current reserve estimates prepared by
an independent petroleum consultant, and shall indicate the
value of the Partnership's assets assuming an orderly
liquidation as of a date immediately prior to the announcement
of the proposed Roll-Up transaction. The appraisal shall
assume an orderly liquidation of Partnership assets over a
12-month period. The terms of the engagement of the
independent expert shall clearly state that the engagement is
for the benefit of the Partnership and the Investor Partners.
A summary of the independent appraisal, indicating all
material assumptions underlying the appraisal, shall be
included in a report to the Investor Partners in connection
with a proposed Roll-Up.
(2) In connection with a proposed Roll-Up, Investor
Partners who vote "no" on the proposal shall be offered the
choice of:
(i) accepting the securities of the Roll-Up
Entity offered in the proposed Roll-Up; or
(ii) (a) remaining as Investor Partners in the
Partnership and preserving their interests therein on
the same terms and conditions as existed previously; or
(b) receiving cash in an amount equal to the Investor
Partners' pro-rata share of the appraised value of the
net assets of the Partnership.
(3) The Partnership shall not participate in any
proposed Roll-Up which, if approved, would result in the
diminishment of any Investor Partner's voting rights under the
Roll-Up Entity's chartering agreement. In no event shall the
democracy rights of Investor Partners in the Roll-Up Entity be
less than those provided for under Sections 7.07 and 7.08 of
this Agreement. If the Roll-Up Entity is a corporation, the
democracy rights of Investor Partners shall correspond to the
democracy rights provided for in this Agreement to the
greatest extent possible.
(4) The Partnership shall not participate in any
proposed Roll-Up transaction which includes provisions which
would operate to materially impede or frustrate the
accumulation of shares by any purchaser of the securities of
the Roll-Up Entity (except to the minimum extent necessary to
preserve the tax status of the Roll-Up Entity); nor shall the
Partnership participate in any proposed Roll-Up transaction
which would limit the ability of an Investor Partner to
exercise the voting rights of its securities of the Roll-Up
Entity on the basis of the number of Partnership Units held by
that Investor Partner.
(5) The Partnership shall not participate in a Roll-Up
in which Investor Partners' rights of access to the records of
the Roll-Up Entity will be less than those provided for under
Section 8.01 of this Agreement.
(6) The Partnership shall not participate in any
proposed Roll-Up transaction in which any of the costs of the
transaction would be borne by the Partnership if the Roll-Up
is not approved by the Investor Partners.
(7) The Partnership shall not participate in a Roll-Up
transaction unless the Roll-Up transaction is approved by at
least 66 2/3% in interest of the Investor Partners.
26
ARTICLE VI
Managing General Partner
6.01 Managing General Partner. The Managing General Partner shall
have the sole and exclusive right and power to manage and control the
affairs of and to operate the Partnership and to do all things necessary
to carry on the business of the Partnership for the purposes described in
Section 1.03 hereof and to conduct the activities of the Partnership as
set forth in Article V hereof. No financial institution or any other
person, firm, or corporation dealing with the Managing General Partner
shall be required to ascertain whether the Managing General Partner is
acting in accordance with this Agreement, but such financial institution
or such other person, firm, or corporation shall be protected in relying
solely upon the deed, transfer, or assurance of and the execution of such
instrument or instruments by the Managing General Partner. The Managing
General Partner shall devote so much of its time to the business of the
Partnership as in its judgment the conduct of the Partnership's business
shall reasonably require and shall not be obligated to do or perform any
act or thing in connection with the business of the Partnership not
expressly set forth herein. The Managing General Partner may engage in
business ventures of any nature and description independently or with
others and neither the Partnership nor any of its Investor Partners shall
have any rights in and to such independent ventures or the income or
profits derived therefrom. However, except as otherwise provided herein,
the Managing General Partner and any of its Affiliates may pursue business
opportunities that are consistent with the Partnership's investment
objectives for their own account only after they have determined that such
opportunity either cannot be pursued by the Partnership because of
insufficient funds or because it is not appropriate for the Partnership
under the existing circumstances.
6.02 Authority of Managing General Partner. The Managing General
Partner is specifically authorized and empowered, on behalf of the
Partnership, and by consent of the Investor Partners herein given, to do
any act or execute any document or enter into any contract or any
agreement of any nature necessary or desirable, in the opinion of the
Managing General Partner, in pursuance of the purposes of the Partnership.
Without limiting the generality of the foregoing, in addition to any and
all other powers conferred upon the Managing General Partner pursuant to
this Agreement and the Act, and except as otherwise prohibited by law or
hereunder, the Managing General Partner shall have the power and authority
to:
(a) Acquire leases and other interests in oil and/or gas
properties in furtherance of the Partnership's business;
(b) Enter into and execute pooling agreements, farm out
agreements, operating agreements, unitization agreements, dry and bottom
hole and acreage contribution letters, construction contracts, and any and
all documents or instruments customarily employed in the oil and gas
industry in connection with the acquisition, sale, exploration,
development, or operation of oil and gas properties, and all other
instruments deemed by the Managing General Partner to be necessary or
appropriate to the proper operation of oil or gas properties or to
effectively and properly perform its duties or exercise its powers
hereunder;
(c) Make expenditures and incur any obligations it deems
necessary to implement the purposes of the Partnership; employ and retain
such personnel as it deems desirable for the conduct of the Partnership's
activities, including employees, consultants, and attorneys; and exercise
on behalf of the Partnership, in such manner as the Managing General
Partner in its sole judgment deems best, of all rights, elections, and
obligations granted to or imposed upon the Partnership;
(d) Manage, operate, and develop any Partnership property,
and enter into operating agreements with respect to properties acquired by
the Partnership, including an operating agreement with the Managing
General Partner as described in the Prospectus, which agreements may
contain such terms, provisions, and conditions as are usual and customary
within the industry and as the Managing General Partner shall approve;
(e) Compromise, sue, or defend any and all claims in favor
of or against the Partnership;
27
(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
(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;
28
(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) Sell, transfer, or assign its interest (except for a
collateral assignment which may be granted to a bank or other financial
institution) in the Partnership, or any part thereof, or otherwise to
withdraw as Managing General Partner of the Partnership without one
hundred twenty (120) days prior written notice and the written consent of
Investor Partners owning a majority of the then outstanding Units.
6.04 Indemnification of Managing General Partner. The Managing
General Partner shall have no liability to the Partnership or to any
Investor Partner for any loss suffered by the Partnership which arises out
of any action or inaction of the Managing General Partner if the Managing
General Partner, in good faith, determined that such course of conduct was
in the best interest of the Partnership, that the Managing General Partner
was acting on behalf of or performing services for the Partnership, and
that such course of conduct did not constitute negligence or misconduct of
the Managing General Partner. The Managing General Partner shall be
indemnified by the Partnership against any losses, judgments, liabilities,
expenses, and amounts paid in settlement of any claims sustained by it in
connection with the Partnership, provided that the Managing General
Partner has determined in good faith that the course of conduct which
caused the loss or liability was in the best interests of the Partnership,
that the Managing General Partner was acting on behalf of or performing
services for the Partnership, and that the same were not the result of
negligence or misconduct on the part of the Managing General Partner.
Indemnification of the Managing General Partner is recoverable only from
the tangible net assets of the Partnership, including the insurance
proceeds from the Partnership's insurance policies and the insurance and
indemnification of the Partnership's subcontractors, and is not
recoverable from the Investor Partners.
29
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.
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.
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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;
(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
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Partnership Agreement by the Additional General Partner, then the
foregoing indemnification by the Managing General Partner shall be
unenforceable as to such Additional General Partner and such Additional
General Partner shall be liable to all other Partners for damages and
obligations resulting therefrom.
7.03 Assignment of Units.
(a) An Investor Partner may transfer all or any portion of
his Units and the transferee shall become a Substituted Investor Partner
(subject to all duties and obligations of an Investor Partner, including
those contained in Section 4.04 herein, except to the extent excepted in
the Act) subject to the following conditions (any transfer of such Units
satisfying such conditions being referred to herein as a "Permitted
Transfer"):
(i) Except in the case of a transfer of Units at death
or involuntarily by operation of law, the transferor and
transferee shall execute and deliver to the Partnership such
documents and instruments of conveyance as may be necessary or
appropriate in the opinion of counsel to the Partnership to
effect such transfer and to confirm the agreement of the
transferee to be bound by the provisions of this Article VII.
In any case not described in the preceding sentence, the
transfer shall be confirmed by presentation to the Partnership
of legal evidence of such transfer, in form and substance
satisfactory to counsel to the Partnership. In all cases, the
Partnership shall be reimbursed by the transferor and/or
transferee for all costs and expenses that it reasonably
incurs in connection with such transfer;
(ii) The transferor and transferee shall furnish the
Partnership with the transferee's taxpayer identification
number and sufficient information to determine the
transferee's initial tax basis in the Units transferred; and
(iii) The written consent of the Managing General
Partner to such transfer shall have been obtained, the
granting or denial of which shall be within the absolute
discretion of the Managing General Partner.
(b) A Person who acquires one or more Units but who is not
admitted as a Substituted Investor Partner pursuant to Section 7.03(c)
hereof shall be entitled only to allocations and distributions with
respect to such Units in accordance with this Agreement, but shall have no
right to any information or accounting of the affairs of the Partnership,
shall not be entitled to inspect the books or records of the Partnership,
and shall not have any of the rights of an Additional General Partner or
a Limited Partner under the Act or the Agreement.
(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
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(v) If the transferee is not an individual of legal
majority, the transferee provides the Partnership with
evidence satisfactory to counsel for the Partnership of the
authority of the transferee to become a Partner and to be
bound by the terms and conditions of this Agreement.
(vi) In any calendar quarter in which a Substituted
Investor Partner is admitted to the Partnership, the Managing
General Partner shall amend the certificate of limited
partnership to effect the substitution of such Substituted
Investor Partners, although the Managing General Partner may
do so more frequently. In the case of assignments, where the
assignee does not become a Substituted Investor Partner, the
Partnership shall recognize the assignment not later than the
last day of the calendar month following receipt of notice of
assignment and required documentation.
(d) Each Investor Partner hereby covenants and agrees with
the Partnership for the benefit of the Partnership and all Partners that
(i) he is not currently making a market in Units and (ii) he will not
transfer any Unit on an established securities market or a secondary
market (or the substantial equivalent thereof) within the meaning of Code
Section 7704(b) (and any regulations, proposed regulations, revenue
rulings, or other official pronouncements of the Service or Treasury
Department that may be promulgated or published thereunder). Each
Investor Partner further agrees that he will not transfer any Unit to any
Person unless such Person agrees to be bound by this Section 7.03 and to
transfer such Units only to Persons who agree to be similarly bound.
7.04 Prohibited Transfers.
(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
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
34
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 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.
35
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 insufficient 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.
(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.
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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;
(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
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
37
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.
(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
normal production, sales of reserves, or product price changes, 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).
38
(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) The Managing General Partner shall cause the
Partnership's independent auditors to audit the financial statements of
the Partnership in accordance with generally accepted auditing standards.
An audit includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements, which would include
an assessment as to whether or not the method used to make allocations of
costs was consistent with the method described in the Prospectus. If the
Managing General partner subsequently decides to allocate expenses in a
manner different from the manner described in the Prospectus, such change
shall be reported by the Managing General Partner to the investor partners
together with an explanation of why such change was made and the basis for
determining the reasonableness of the new allocation method.
(g) Such other reports and financial statements as the
Managing General Partner shall determine from time to time.
(h) Concurrently with their transmittal to Investor Partners
and as required, the Managing General Partner shall file a copy of each
such report with the California Commissioner of Corporations and with the
securities divisions of other states.
8.03 Bank Accounts. All funds of the Partnership shall be
deposited in such separate bank account or accounts, short term
obligations of the U.S. Government or its agencies, or other
interest-bearing investments and money market or liquid asset mutual funds
as shall be determined by the Managing General Partner. All withdrawals
therefrom shall be made upon checks signed by the Managing General Partner
or any person authorized to do so by the Managing General Partner.
8.04 Federal Income Tax Elections.
(a) Except as otherwise provided in this Section 8.04, all
elections required or permitted to be made by the Partnership under the
Code shall be made by the Managing General Partner in its sole discretion.
Each Partner agrees to provide the Partnership with all information
necessary to give effect to any election to be made by the Partnership.
(b) The Partnership shall elect to currently deduct IDC as
an expense for income tax purposes and shall require any partnership,
joint venture, or other arrangement in which it is a party to make such an
election.
39
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.
(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:
40
(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
(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.
41
(e) Such certificates, instruments, and documents as may be
required to be filed with the Department of Interior (including any
bureau, office or other unit thereof, whether in Washington, D.C. or in
the field, or any officer or employee thereof), as well as with any other
federal or state agencies, departments, bureaus, offices, or authorities
and pertaining to (i) any and all offers to lease, leases (including
amendments, modifications, supplements, renewals, and exchanges thereof)
of, or with respect to, any lands under the jurisdiction of the United
States or any state including without limitation lands within the public
domain, and acquired lands, and provides for the leasing thereof; (ii) all
statements of interest and holdings on behalf of the Partnership or the
undersigned; (iii) any other statements, notices, or communications
required or permitted to be filed or which may hereafter be required or
permitted to be filed under any law, rule, or regulation of the United
States, or any state relating to the leasing of lands for oil or gas
exploration or development; (iv) any request for approval of assignments
or transfers of oil and gas leases, any unitization or pooling agreements
and any other documents relating to lands under the jurisdiction of the
United States or any state; and (v) any other documents or instruments
which said attorney-in-fact in its sole discretion shall determine should
be filed.
(f) Any further document, including furnishing verified
copies of the Agreement and/or excerpts therefrom, which said
attorney-in-fact shall consider necessary or convenient in connection with
any of the foregoing, hereby giving said attorney-in-fact full power and
authority to do and perform each and every act and thing whatsoever
requisite and necessary to be done in and about the foregoing as fully as
the undersigned might and could do if personally present, and hereby
ratifying and confirming all that said attorney-in-fact shall lawfully do
to cause to be done by virtue hereof.
10.02 Nature of 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
42
Exhibit A attached hereto. Unless otherwise expressly set forth in this
Agreement to the contrary, any such notice shall be deemed to be given on
the date on which the same was deposited in a regularly maintained
receptacle for the deposit of United States mail, addressed and sent as
aforesaid.
11.03 Paragraph Headings. The headings in this Agreement are
inserted for convenience and identification only and are in no way
intended to describe, interpret, define, or limit the scope, extent, or
intent of this Agreement or any provision hereof.
11.04 Severability. Every portion of this Agreement is intended to
be severable. If any term or provision hereof is illegal or invalid by
any reason whatsoever, such illegality or invalidity shall not affect the
validity of the remainder of this Agreement.
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;
43
(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
(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.
* * * * *
44
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
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 PURCHASED
Name:__________________________________
(Print Name)
______________________________________
(Signature)
SUBSCRIPTION PRICE
$__________________
Address:_______________________________
_______________________________________
By: Petroleum Development Corporation
By: __________________________________
its______________________________
Attorney-in-Fact
45
<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
46
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 (b) or (c) above.
(g) I certify that the number shown as my Social Security or
Taxpayer Identification Number on the signature page is correct.
B-1
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.
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.
NOTICES
(i) The purchase of Units as an Additional General Partner
involves a risk of unlimited liability to the extent that the
Partnership's liabilities exceed its insurance proceeds, the Partnership's
assets, and indemnification by the Managing General Partner, as described
in "Risk Factors" in the Prospectus.
(ii) The NASD requires the Soliciting Dealer or registered
representative to inform potential investors of all pertinent facts
relating to the liquidity and marketability of the Units, including the
following: (A) the risks involved in the offering, including the
speculative nature of the investment and the speculative nature of
drilling for oil and gas; (B) the financial hazards involved in the
offering, including the risk of losing my entire investment; (C) the lack
of liquidity of this investment; (D) the restrictions of transferability
of the Units; and (E) the tax consequences of the investment.
(iii) The investment IN THE UNITS is not liquid.
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.
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.
B-2
Date: _________________, 2000.
____________________________________
Signature
____________________________________
Signature
_____________________________
____________________________________
Please Print Name Please Print
Name
_____________________________ __________________________________
Social Security or Tax Social Security or Tax
Identification Number Identification Number
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: (check one below):
IF NO SELECTION IS MADE, THE
PARTNERSHIP CANNOT ACCEPT YOUR
SUBSCRIPTION AND WILL HAVE TO [ ] Units as an Additional General Partner
[ ] 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)
B-3
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:_______________________________
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
_______________________________,2000
Area Code Telephone Number FC RR AE Signature Date
B-4
APPENDIX C TO PROSPECTUS
PDC 2000 DRILLING PROGRAM
SPECIAL SUBSCRIPTION INSTRUCTIONS
Checks for Units should be made payable to "Chase 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 yearly
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.
In addition, an Alaska resident must have either: (i) a
minimum annual gross income of $60,000 and a minimum net worth
of $60,000, exclusive of principal automobile, principal
residence, and home furnishings, or (ii) a minimum net worth
of $225,000, exclusive of principal automobile, principal
residence, and home furnishings.
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.
Notice to New Hampshire Investors.
- 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), and $50,000
in taxable income.
C-1
Subscribers of Limited Partnership Interests:
- 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.
- 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, Vermont or Washington 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, Vermont and Washington 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.
C-2
- If resident of South Dakota , 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, New Mexico Ohio, Pennsylvania, or South
Dakota resident, my investment in the Partnership will not be
equal to more than 10% of my net worth.
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.
C-3
- 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 THEREFORE,
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.
(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;
C-4
(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;
(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
APPENDIX D TO THE PROSPECTUS
DUANE, MORRIS & HECKSCHER LLP
1667 K Street, NW, Suite 700
Washington, DC 20006
June 1, 2000
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 Partnerships (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.
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.
D-1
The following opinion and statements are based upon the provisions
of the Internal Revenue Code of 1986, as amended (the "Code"), including
revisions to the Code effected by the Revenue Reconciliation Act of 1990
(the "1990 Act"), which was enacted into law on November 5, 1990, the
Omnibus Budget Reconciliation Act of 1990, the 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 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
4. The deductibility of losses generated from the Partnership
will not be limited by the at risk rules or the limitations related to
an Investor's adjusted basis in his 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.
D-3
5. Whether the fees to be paid to the Managing General Partner
and to third parties will be deductible, due to the factual nature of
the issue. Due to the inherently factual nature of the proper
allocation of expenses among nondeductible syndication expenses,
amortizable organization expenses, amortizable "start-up" expenditures,
and currently deductible items, and because the issues involve questions
concerning both the nature of the services performed and to be performed
and the reasonableness of amounts charged, we are unable to express an
opinion regarding such treatment.
General Information: Certain matters contained herein are not
considered to address a material tax consequence and are for general
information, including the matters contained in sections dealing with
gain or loss on the sale of Units or of property, Partnership
distributions, tax audits, penalties, and state, local, and self-
employment tax.
Our opinions are also based upon the facts described in this
Prospectus and upon certain representations made to us by the Managing
General Partner for the purpose of permitting us to render our opinions,
including the following representations with respect to the Program:
1. The Partnership Agreement to be entered into by and among
the Managing General Partner and Investor Partners and any amendments
thereto will be duly executed and will be made available to any Investor
Partner upon written request. The Partnership Agreement will be duly
recorded in all places required under the West Virginia Uniform Limited
Partnership Act (the "Act") for the due formation of the Partnership and
for the continuation thereof in accordance with the terms of the
Partnership Agreement. The Partnership will at all times be operated in
accordance with the terms of the Partnership Agreement, the Prospectus,
and the Act.
2. No election will be made by the Partnership, Investor
Partners, or Managing General Partner to be excluded from the
application of the provisions of Subchapter K of the Code.
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.
D-4
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 March 30, 2001 with respect to Partnerships designated
"PDC 2000-_ 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.
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 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. 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 will not permit 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.
D-5
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.
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.
D-6
B. Publicly Traded Partnerships
The Revenue Act of 1987 (the "1987 Act") added Code section 7704,
"Certain Publicly Traded Partnerships Treated as Corporations." In
treating certain "publicly traded partnerships" ("PTPs") as corporations
for federal income tax purposes, Congress defined a PTP as any
partnership, interests in which are either traded on an established
securities market or readily tradable on a secondary market (or the
substantial equivalent thereof). Code section 7704(b). 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.
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
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."
D-7
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 Paragrph 7704 in the absence of
the Partnership's interests being "readily tradable on a secondary
market (or the substantial equivalent thereof)."
Notwithstanding the above, the Service may promulgate regulations
or release announcements which take the position that interests in
partnerships such as the Partnership are readily tradable on a secondary
market or the substantial equivalent thereof. However, treatment of the
Partnership as a PTP should not result in its treatment as a corporation
for federal income tax purposes due to the exception contained in Code
section 7704(c) relating to PTPs meeting the 90% of gross income test so long
as such gross income test is satisfied.
C. Summary
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 paragraph 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.
D-8
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.
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
D-9
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.
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
D-10
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 no__deductible as IDC:
[O]nly that portion of the amount of the taxpayer's total
investment that is attributable to intangible drilling and
development costs that would have been incurred in an arm's-
length transaction with an unrelated drilling contractor (in
accordance with the economic realities of the transaction)
is deductible [as IDC].
To the extent the Partnership's prices meet the reasonable price
standards imposed by Bernuth, supra, and Rev. Rul 73-211, supra, and to
the extent such amounts are not allocable to tangible property,
leasehold costs, and the like, the amounts paid to the Managing General
Partner under the drilling contract should qualify as IDC and should be
deductible at the time described below under "B. Timing of Deductions."
That portion of the amount paid to the Managing General Partner that is
in excess of the amount that would be charged by an independent driller
under similar conditions will not qualify as IDC and will be required to
be capitalized.
We are unable to express an opinion regarding the reasonableness
or proper characterization of the payments under the drilling agreement,
since the determination of whether the amounts are reasonable or
excessive is inherently factual in nature. No assurance can be given
that the Service will not characterize a portion of the amount paid to
the Managing General Partner as an excessive payment, to be capitalized
as a leasehold cost, assignment fee, syndication fee, organization fee,
or other cost, 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).
D-11
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).
Notwithstanding the above, the deductibility of any prepaid IDC
will be subject to the limitations of case law. These limitations
provide that prepaid IDC is deductible when paid if (i) the expenditure
constitutes a payment that is not merely a deposit, (ii) the payment is
made for a business purpose, and (iii) deductions attributable to such
outlay do not result in a material distortion of income. See Keller v.
Commissioner, 79 T.C. 7 (1982), aff'd, 725 F.2d 1173 (8th Cir. 1984),
Rev. Rul. 71-252, 1971-1 C.B. 146, Pauley v. U.S., 63-1 U.S.T.C.
paragraph 9280 (S.D. Cal. 1963), Rev. Rul. 80-71, 1980-1 C.B. 106,
Jolley v. Commissioner, 47 T.C.M. 1082 (1984), Dillingham v. U.S., 81-2
U.S.T.C. paragraph 9601 (W.D. Okla. 1981), and Stradlings Building
Materials, Inc. v. Commissioner, 76 T.C. 84 (1981). Generally, these
requirements may be met by a showing of a legally binding obligation
(i.e., the payment was not merely a deposit), of a legitimate business
purpose for the payment, that performance of the services was required
within a reasonable time, and of an arm's-length price. Similar
requirements apply to cash basis taxpayers seeking to deduct prepaid
IDC.
D-12
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 Partnerships designated "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.
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.
D-13
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-14
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 Partnerships," and 2000 for Partnerships designated "PDC 2000-
_ Limited Partnership" will be allowable as a deduction in 1998 for
Partnerships designated "PDC 1998-_ Limited Partnership," 1999 for
Partnerships designated "PDC 1999-_ Limited Partnerships," and 2000 for
Partnerships designated "PDC 2000-_ Limited Partnership" 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 Partnerships," and 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," 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 or 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.
D-15
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).
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. sections 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).
D-16
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 purpose. 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.
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.
D-17
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.
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).
D-18
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.
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.
D-19
BASIS AND AT RISK LIMITATIONS
A Partner's share of Partnership losses will not be allowed as a
deduction to the extent such share exceeds the amount of the Partner's
adjusted tax basis in his Units. A Partner's initial adjusted tax basis
in his Units will generally be equal to the cash he has invested to
purchase his Units. Such adjusted tax basis will generally be increased
by (i) additional amounts invested in the Partnership, including his
share of net income, (ii) additional capital contributions, if any, and
(iii) his share of Partnership borrowings, if any, based on the extent
of his economic risk of loss for such borrowings. Such adjusted tax
basis will generally be reduced, but not below zero by (i) his share of
loss, (ii) his depletion deductions on his share of oil and gas income
(until such deductions exhaust his share of the basis of property
subject to depletion), (iii) distributions of cash and the adjusted
basis of property other than cash made to him, and (iv) his share of
reduction in the amount of indebtedness previously included in his
basis.
In addition, Code section 465 provides, in part, that, if an
individual or a closely held C (i.e., regularly taxed) corporation
engages in any activity to which Code section 465 applies, any loss from
that activity is allowed only to the extent of the aggregate amount with
respect to which the taxpayer is "at risk" for such activity at the
close of the taxable year. Code section 465(a)(1). A closely held C
corporation is a corporation, more than fifty percent (50%) of the stock
of which is owned, directly or indirectly, at any time during the last
half of the taxable year by or for not more than five (5) individuals.
Code sections 465(a)(1)(B), 542(a)(2). For purposes of Code
section 465, a loss is defined as the excess of otherwise allowable
deductions attributable to an activity over the income received or
accrued from that activity. Code section 465(d). Any such loss
disallowed by Code section 465 shall be treated as a deduction allocable
to the activity in the first succeeding taxable year. Code
section 465(a)(2).
Code section 465(b)(1) provides that a taxpayer will be considered
as being "at risk" for an activity with respect to amounts including (i)
the amount of money and the adjusted basis of other property contributed
by the taxpayer to the activity, and (ii) amounts borrowed with respect
to such activity to the extent that the taxpayer (I) is personally
liable for the repayment of such amounts, or (II) has pledged property,
other than property used in the activity, as security for such borrowed
amounts (to the extent of the net fair market value of the taxpayer's
interest in such property). No property can be taken into account as
security if such property is directly or indirectly financed by
indebtedness that is secured by property used in the activity. Code
section 465(b)(2). Further, amounts borrowed by the taxpayer shall not
be taken into account if such amounts are borrowed (i) from any person
who has an interest (other than an interest as a creditor) in such
activity, or (ii) from a related person to a person (other than the
taxpayer) having such an interest. Code section 465(b)(3).
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).
D-20
Finally, no taxpayer is considered at risk with respect to amounts
for which the taxpayer is protected against loss through nonrecourse
financing, guarantees, stop loss agreements, or other similar
arrangements. Code section 465(b)(4).
The Code provides that a taxpayer must recognize taxable income to
the extent that his "at risk" amount is reduced below zero. This
recaptured income is limited to the sum of the loss deductions
previously allowed to the taxpayer, less any amounts previously
recaptured. A taxpayer may be allowed a deduction for the recaptured
amounts included in his taxable income if and when he increases his
amount "at risk" in a subsequent taxable year.
The Treasury has published proposed regulations relating to the at
risk provisions of Code section 465. These proposed regulations provide
that a taxpayer's at risk amount will include "personal funds"
contributed by the taxpayer to an activity. Prop. Treas. Reg.
section 1.465-22(a). "Personal funds" and "personal assets" are defined
in Prop. Treas. Reg. section 1.465-9(f) as funds and assets which (i)
are owned by the taxpayer, (ii) are not acquired through borrowing, and
(iii) have a basis equal to their fair market value.
In addition to a taxpayer's amount at risk being increased by the
amount of personal funds contributed to the activity, the excess of the
taxpayer's share of all items of income received or accrued from an
activity during a taxable year over the taxpayer's share of allowable
deductions from the activity for the year will also increase the amount
at risk. Prop. Treas. Reg. section 1.465-22. A taxpayer's amount at
risk will be decreased by (i) the amount of money withdrawn from the
activity by or on behalf of the taxpayer, including distributions from a
partnership, and (ii) the amount of loss from the activity allowed as a
deduction under Code section 465(a). Id.
The Partners will purchase Units by tendering cash to the
Partnership. To the extent the cash contributed constitutes the
"personal funds" of the Partners, the Partners should be considered at
risk with respect to those amounts. To the extent the cash contributed
constitutes "personal funds," in our opinion, neither the at risk rules
nor the limitations related to adjusted basis will limit the
deductibility of losses generated from the Partnership.
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).
D-21
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 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).
D-23
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 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
D-23
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.
D-24
Notwithstanding the above, there can be no assurance that the
Service will not contend that all general partner interests should be
regarded as interests in a passive activity from the Partnership's
inception due to the conversion feature contained in the Partnership
Agreement. However, due to the exposure to unlimited liability for
Partnership obligations incurred prior to such conversion, an attack by
the Service with respect to the foregoing should not be successful. In
addition, the temporary regulations, at section 1.469-1T(e)(4)(iii),
example (1), respect the nature of a general partnership interest prior
to its conversion into limited partnership form:
A, a calendar year individual, acquires on
January 1, 1987, a general partnership interest
in P, a calendar year partnership that holds a
working interest in an oil or gas property.
Pursuant to the partnership agreement, A is
entitled to convert the general partnership
interest into a limited partnership interest at
any time. On December 1, 1987, pursuant to a
contract with D, an independent drilling
contractor, P commences drilling a single well
pursuant to the working interest. Under 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.
D-25
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.
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.
D-26
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) pursuant to Treas. Reg.
section 1.708-1(b)(1)(ii) a transaction governed by Code section 721 is
not treated as a sale or exchange for purposes of Code section 708.
Assuming that Rev. Rul. 84-52, supra, is not overruled, revoked,
or modified, the Partnership, in our opinion, will not be terminated
under Code section 708 solely as a result of the conversion of
Partnership interests.
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 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.
D-27
Code section 1254(a) provides, in part, that when a property is
disposed of, the taxpayer must recapture as ordinary income any gain on
disposition in an amount equal to the aggregate of amounts deductible as
IDC, in excess of the amount deductible without regard to Code
section 263, and depletion. Code section 1254 (a) (1). Code
section 1254(b) provides that rules similar to the rules of subsections
(b) and (c) of Code section 1245 are to be applied for purposes of Code
section 1254. Consequently, to the extent that a Partner could
recognize ordinary income under Code section 1245 upon conversion, the
Partner could also recognize ordinary income under Code section 1254.
Losses arising from the holding of working interests in oil and
gas properties directly or through an entity that does not limit the
holder's liability are not subject to the passive loss rules. Temporary
and Proposed Regulations provide that, if the form of ownership is
converted from a type that does not limit liability to a type that does
limit liability, the portion of any losses (including those arising from
the deduction of IDC) attributable to services or materials which have
not yet been provided at the time of such conversion will constitute
losses from a passive activity. Thus, in our opinion, if a Partner were
to convert his general partner interest to that of a limited partner
prior to the time that all of the services or materials comprising the
IDC of a well had been provided, at the time of the conversion such
services and materials will constitute losses from a passive activity
and be subject to the passive loss limitations. Similarly in such a
situation, a portion of the income from the well would constitute
passive income. If the conversion were to occur after the filing of the
Partnership's information tax return but prior to the completion of the
drilling and development of a well, an amended return might have to be
filed, which might also require the Investors to file amended returns.
Further, the Code provides that if a taxpayer has any loss attributable
to a working interest which is treated in any taxable year as a loss
which is not from a passive activity, then any net income attributable
to the working interest in any succeeding taxable year is treated as
income of the taxpayer which is not from a passive activity.
Accordingly, if an Additional General Partner converts his interest into
a Limited Partner interest, any income from that interest with respect
to which he claimed deductions will be treated as nonpassive income.
ALTERNATIVE MINIMUM TAX
For taxable years beginning after December 31, 1992, Code 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).
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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, with certain adjustments, 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.
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. Taxpayers which do not meet the definition of an integrated
oil company as defined in Code section 291(b)(4) are not subject to the
preference item for "excess IDC." Code section 57(a)(2)(E)(i). The
benefit of the elimination of the preference is limited in any taxable
year to an amount equal to 40 percent of the alternative minimum taxable
income for the year computed as if the prior law "excess IDC" preference
item has not been eliminated. Code section 57(a)(2)(E)(ii). Excess IDC
is defined as the excess of (i) IDC paid or incurred (other than costs
incurred in drilling a nonproductive well) with respect to which a
deduction is allowable under Code section 263(c) for the taxable year
over (ii) the amount which would have been allowable for the taxable
year if such costs had been capitalized and (I) amortized over a 120
month period beginning with the month in which production from such well
begins or (II) recovered through cost depletion. Code
section 57(a)(2)(B). However, any portion of the IDC to which an
election under Code section 59(e) applies will not be treated as an item
of tax preference under Code section 57(a). Code section 59(e)(6).
With respect to IDC paid or incurred, corporate and individual taxpayers
are 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. Excess depletion constitutes a preference only in the case of
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).
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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.
Gain or loss recognized upon the disposition of property used in a
trade or business and held for more than one year will be treated as
long term capital gain or as ordinary loss. Code section 1231(a).
Notwithstanding the above, however, any gain realized may be taxed as
ordinary income under one of several "recapture" provisions of the Code
or under the characterization rules relating to "dealers" in personal
property.
Code section 1254 generally provides for the recapture of capital
gains, arising from the sale of property which was placed in service
after 1986, as ordinary income to the extent of the lesser of (i) the
gain realized upon sale of the property, or (ii) the sum of (I) all IDC
previously deducted and (II) all depletion deductions that reduced the
property's basis. Code section 1254(a)(1).
Ordinary income may also result from the recapture, pursuant to
Code section 1245, of depreciation on the Partnership properties. Such
recapture is the amount by which (i) the lower of (I) the recomputed
basis of the property, or (II) the amount realized on the sale of the
property exceeds (ii) the property's adjusted basis. Code
section 1245(a)(1). Recomputed basis is generally the property's
adjusted basis increased by depreciation and amortization deductions
previously claimed with respect to the property. Code
section 1245(a)(2).
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Unrecaptured section 1250 gain may result from the recapture of
depreciation related to the sale of the Partnership's section 1250
property held for more than one year. Code section 1(h)(7). Currently,
unrecaptured section 1250 gain is taxed at a rate of 25%. Code section
1(h)(1)(D).
GAIN OR LOSS ON SALE OF UNITS
If the Units are capital assets in the hands of the Partners, gain
or loss realized by any such holders on the sale or other disposition of
a Unit will be characterized as capital gain or capital loss. Code
section 1221. Such gain or loss will be a long term capital gain or
loss if the Unit is held for more than one year and 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
"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.
Property treated as an "inventory item" for purposes of Code
section 751 includes (i) stock in trade of the partnership or other
property of a kind which would properly be included in its inventory if
on hand at the end of the taxable year, (ii) property held by the
partnership primarily for sale to customers in the ordinary course of
its trade or business, and (iii) any other partnership property which
would constitute neither a capital asset nor property used in a trade or
business under Code section 1231. Code sections 751(d)(2) and 1221(1).
Under the aforementioned provisions, a Partner would recognize
ordinary income with respect to any deemed sale of assets under Code
section 751; further, this ordinary income may be recognized even if the
total amount realized on the sale of a Unit is equal to or less than the
Partner's basis in the Unit.
Any partner who sells or exchanges interests in a partnership
holding unrealized receivables (which include IDC recapture and other
items) or certain inventory items must notify the partnership of such
transaction in accordance with Regulations under Code section 6050K and
must attach a statement to his tax return reflecting certain facts
regarding the sale or exchange. Regulations promulgated by the service
provide that such notice to the partnership must be given in writing
within 30 days of the sale or exchange (or, if earlier, by January 15 of
the calendar year following the calendar year in which the exchange
occurred), and must include names, addresses, and taxpayer
identification numbers (if known) of the transferor and transferee and
the date of the exchange. Code section 6721 provides that persons who
fail to furnish this information to the partnership will be penalized
$50 for each such failure, or, if such failure is due to intentional
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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, i.e., actively traded financial instruments, foreign
currencies or interests in certain defined properties. Further, the
Partnership Agreement prohibits distributions to any Investor Partner to
the extent such would create or increase a deficit in the Partner's
Capital Account.
PARTNERSHIP ALLOCATIONS
Allocations - General. Generally, a partner's taxable income is
increased or decreased by his ratable share of partnership income or
loss. Code section 701. However, the availability of these losses may
be limited by the at risk rules of Code section 465, the passive
activity rules of Code section 469, and the adjusted basis provisions of Code
section 704(d).
Code section 704(b) provides that if a partnership agreement does
not provide for the allocation of each partner's distributive share of
partnership income, gain, loss, deduction, or credit, or if the
allocation of such items under the partnership agreement lacks
"substantial economic effect," then each partner's share of those items
must be allocated "in accordance with the partner's interest in the
partnership."
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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 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).
D-33
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
D-34
liquidation is made in accordance with capital accounts." The ruling
noted that the investors "should have been allocated their share of
costs over the intangible drilling costs." Id. The question whether
economic effect is "substantial" is one of fact which may depend in part
on the timing of income and deductions and on consideration of the
investors' tax attributes unrelated to their investment in Units, and
thus is not a question upon which a legal opinion can ordinarily be
expressed. However, to the extent the tax brackets of all Partners do
not differ at the time the allocation becomes part of the partnership
agreement, the economic effect of the allocation provisions should be
considered to be substantial.
Code section 613A(c)(7)(D) requires that the basis of oil and gas
properties owned by a partnership be allocated to the partners in
accordance with their interests in the capital or income of the
partnership. Final Regulations issued under Code section 613A(c)(7)(D)
indicate that such basis must be allocated in accordance with the
partners' interests in the capital of the partnership if their interests
in partnership income vary over the life of the partnership for any
reason other than for reasons such as the admission of a new partner.
Reg. section 1.613A-3(e)(2). The terms "capital" and "income" are not defined
in the Code or in the Regulations under Section 613A. The Regulations
under Code section 704 indicate that if all partnership allocations of income,
gain, loss, and deduction (or items thereof) have substantial economic
effect, an allocation of the adjusted basis of an oil or gas property
among the partners will be deemed to be made in accordance with the
partners' interests in partnership capital or income and will
accordingly be recognized.
Pursuant to the Partnership Agreement, (i) allocations will be
made as mandated by the Regulations, (ii) liquidating distributions will
be made in accordance with positive capital account balances, and (iii)
a "qualified income offset" provision applies. However, while capital
will be owned 78.125% by the Investor Partners and 21.875% by the
Managing General Partner, IDC will be allocated 100% to the Investor
Partners and other tax items will be allocated 80% to the Investor
Partners. Except with respect to those excess allocations, under the
Partnership Agreement the basis in oil and gas properties will be
allocated in proportion to each Partner's respective share of the costs
which entered into the Partnership's adjusted basis for each depletable
property. Such allocations of basis appear reasonable and in compliance
with the Regulations under Section 704. Nevertheless, the Service may
contend that the allocation to the Investors of IDC (100%) in excess of
their capital contributions (78.125%) or the allocation to the Managing
General Partner of other tax items (100% ranging to 0% upon the
occurrence of certain events) in excess of its capital contribution
(21.875%) is invalid and may reallocate such excess IDC or other items
to the other Partners. Any such reallocation could increase an Investor
Partner's tax liability. However, no assurance can be given, and we are
unable to express an opinion, as to whether any special allocation of an
item which is dependent upon basis in an oil and gas property will be
recognized by the Service.
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 "substantially appreciated inventory items"
or "unrealized receivables," as those terms are defined in Code section 751.
Nonrecourse Deductions. As noted above, an allocation of loss or
deduction attributable to nonrecourse liabilities of a partnership
cannot have economic effect because the creditor alone bears any
economic burden that corresponds to such an allocation. Nevertheless,
the Temporary Regulations provide a test under which certain allocations
of nonrecourse deductions will be deemed to be in accordance with the
partners' interests in the partnership.
D-35
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.
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).
D-36
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" ambit of Code section 183, the Service
could disallow all or a portion of the deductions and credits generated
by the Partnership's activities.
Code section 183(d) generally provides for a presumption that an
activity is entered into for profit within the meaning of the statute
where gross income from the activity exceeds the deductions attributable
to such activity for three or more of the five consecutive taxable years
ending with the taxable year in question. At the taxpayer's election,
such presumption can relate to three or more of the taxable years in the
5-year period beginning with the taxable year in which the taxpayer
first engages in the activity. Temp. Treas. Reg. section 12.9. Whether an
activity is engaged in for profit is determined under Code sections 162
(relating to trade or business deductions) and 212(1) and (2) (relating
to income producing deductions) except insofar as the above-described
presumption applies. Treas. Reg. section 1.183-1(a).
To establish that he is engaged in either a trade or business or
an income producing activity, a Partner must be able to prove that he is
engaged in the Transaction with an "actual and honest profit objective,"
Fox v. Commissioner, 80 T.C. 972, 1006 (1983), aff'd sub nom., Barnard
v. Commissioner, 731 F.2d 230 (4th Cir. 1984), and that his profit
objective is bona fide. Bessenyey v. Commissioner, 45 T.C. 261, 274
(1965), aff'd, 379 F.2d 252 (2d Cir. 1967), cert. denied, 389 U.S. 931
(1967). The inquiry turns on whether the primary purpose and intention
of the Partner in engaging in the activity is, in fact, to make a profit
apart from tax considerations. Hager v. Commissioner, 76 T.C. 759, 784.
Such objective need not be reasonable, only honest, and the question of
objective is to be determined from all the facts and circumstances.
Sutton v. Commissioner, 84 T.C. 210 (1985), aff'd, 788 F.2d 695 (11th
Cir. 1986). Among the factors that will normally be considered are:
(i) the manner in which the taxpayer carries on the activity, (ii) the
expertise of the taxpayer or his advisors, (iii) the time and effort
expended by the taxpayer in carrying on the activity, (iv) whether an
expectation exists that the assets used in the activity may appreciate
in value, (v) the success of the taxpayer in carrying on similar or
dissimilar activities, (vi) the taxpayer's history of income or losses
with respect to the activity, (vii) the amount of occasional profits, if
any, which are earned, and (viii) the financial status of the taxpayer.
Treas. Reg. section 1.183-2(b). Where application of such factors to a
particular activity is difficult, however, the Court will consider the
totality of the circumstances instead. Estate of Baron v. Commissioner,
83 T.C. 542 (1984), aff'd, 798 F.2d 65 (2d Cir. 1986).
As noted, the issue is one of fact to be resolved not on the basis
of any one factor but on the basis of all the facts and circumstances.
Treas. Reg. section 1.183-2(b). Greater weight is given to objective 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.
D-38
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.
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.
The Taxpayer Relief Act of 1997 added new sections 771-777 to the
Code providing for alternative reporting treatment for partnerships and
their partners in the case of partnerships having 100 or more partners.
In general these provisions provide for somewhat simplified reporting of
partnership items on the forms K-1 supplied to partners. The Managing
General Partner has not determined whether to make the election provided
pursuant to these new Code provisions.
D-39
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 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. setion 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).
D-40
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.
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.
D-41
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.
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
DUANE, MORRIS & HECKSCHER LLP
D-42
