As filed with the Securities and Exchange Commission on , 2000
Registration No. 333-4762
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM S-1
REGISTRATION STATEMENT
Under
THE SECURITIES ACT OF 1933
PDC 2003 DRILLING PROGRAM
(Exact name of registrant as specified in its charter)
West Virginia 1381
(State or other jurisdiction of Primary Standard
Industrial
incorporation or organization)
Classification Code Number)
Applied for
(IRS Employer Identification No.)
103 East Main Street
Bridgeport, West Virginia 26330
304/842-6256
(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
304/842-6256
(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., Suite 700
Washington, D.C. 20006-1608
(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]
If this form is filed to register additional securities for an
offering
pursuant to Rule 462(b) under the Securities Act, check the following box
and
list the Securities Act registration statement number of the earlier
effective
registration statement for the same offering. [ ]
If this form is a post-effective amendment filed pursuant to Rule
462(c)
under the Securities Act, check the following box and list the Securities
Act
registration statement number of the earlier effective registration
statement for
the same offering. [ ]
If this form is a post-effective amendment filed pursuant to Rule
462(d)
under the Securities Act, check the following box and list the Securities
Act
registration statement number of the earlier effective registration
statement for
the same offering. [ ]
If delivery of the prospectus is expected to be made pursuant to Rule
434,
check the following box. [ ]
<TABLE>
<C> <C> <C> <C>
CALCULATION OF REGISTRATION FEE
Proposed Proposed
maximum maximum
offering aggregate Amount of
Title of each class of Amount to be price offering
registration
securities to be registered registered per unit price fee
Units of general and 7,500 units $20,000 $150,000,000 $39,600
limited
partnership interest
</TABLE>
The registrant hereby amends this registration statement on such date or
dates
as may be necessary to delay its effective date until the registrant shall
file
a further amendment which specifically states that this registration
statement
shall thereafter become effective in accordance with Section 8(a) of the
Securities Act of 1933, or until the registration statement shall become
effective on such date as the Commission, acting pursuant to Section 8(a)
shall
determine.
PROSPECTUS
PDC 2003 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 2003 Drilling Program, which we refer to as the " in this
prospectus, is a series of up to twelve limited partnerships which to
drill,
own, and operate natural gas wells in Colorado, Michigan, West Virginia,
Pennsylvania, Utah and other states.
These Securities Are Speculative and Involve a High Degree of Risk.
See
"Risk Factors" on page . Investment risks and considerations
include:
- Drilling gas wells is highly risky; an investor might lose his or her
entire investment in the .
- No investor may participate in the management of any partnership.
- The has not yet selected any prospects for gas drilling; thus, no
investor can evaluate any prospect before investing.
- Investors may be subject to unlimited liability.
- No public market exists or will develop for the ; may not be
able
to sell your when or if you wish.
- Significant tax considerations are involved in an investment.
We must sell the minimum of $1.5 million of in a limited
partnership
($2.5 million with respect to each of PDC 2001-D Limited Partnership, PDC
2002-D
Limited Partnership and PDC 2003-D Limited Partnership) if we sell any
.
We will sell beyond the minimum amount on a best efforts basis.
The
offerings of partnerships designated PDC 2001- Limited Partnership will
terminate
on December 31, 2001; of those designated PDC 2002- Limited Partnership will
terminate on December 31, 2002; and of those designated PDC 2003- Limited
Partnership will terminate on December 31, 2003. Chase Manhattan Trust
Company
will hold subscription proceeds of each in a separate escrow account
and
will not release funds to a before the sale of the minimum number
of
that . See "Plan of Distribution" on page .
Neither the Securities and Exchange Commission nor any state
securities
commission has approved or disapproved of these securities 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>
Price to
Public Underwriting Discounts
and Commissions Proceeds to the
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>
and an Affiliate of the Managing General Partner
The date of this prospectus is , 2001.
<TABLE>
<C> <C>
TABLE OF CONTENTS
Page
SUMMARY 1
RISK FACTORS
Special Risks of the Partnerships
Drilling natural gas wells is speculative, may be unprofitable, and
may
result in the total loss of your investment
The Managing General Partner has not selected any prospects for
acquisition, and as a result the will be unable to evaluate any prospect
before
they invest in the 5
Because of a lengthy offering period, delays in the investment
of an
investor's subscription are likely
will be individually liable for obligations and
liabilities
beyond the amount of their subscriptions, assets, and the assets of
the
Managing General Partner
The Managing General Partner and its will receive
compensation from the upon funding of the and throughout the
life
of the
wells might not produce commercial quantities of natural
gas
There will be no public market for the , and as a result
an
may not be able to sell his or her
Sufficient insurance coverage may not be available for the
thereby increasing the risk of loss for the
which drills fewer wells will be less diversified, thereby
increasing the risk of financial loss for the investors
Through their involvement in and other non-
activities, the Managing General Partner and its have interests
which conflict with those of the 8
Unaffiliated persons might manage jointly-owned
prospects;
a could be financially liable for obligations of
jointly-owned
prospects
might not have sufficient capital for its operations
and
other partnerships sponsored by the Managing General Partner may compete
with
each other for prospects, equipment, contractors, and personnel; as a
result, the partnership may find it more difficult to operate
effectively
may drill exploratory wells, which involves a greater risk
of
financial loss than drilling development wells
The results of drilling previous partnerships sponsored by the
Managing General Partner are not indicative of the results to be experienced
by
the
In view of the cost sharing arrangements, the will bear
the
substantial amount of costs and risks of non-commercial wells
Investor may be personally liable the limited
partnership agreement
Indemnification of by the Managing General Partner
could
reduce the value of the and the investment interests of the
Receipt by distributions could result in liability
of
to the
A significant financial loss by the Managing General Partner
could
distribution if the distribution would cause a capital
account
deficit
The dealer manager is not independent and has not conducted an
independent due diligence evaluation of the offering
Risks Pertaining to Natural Gas Investments
The drilling of gas wells is highly speculative and risky and
may
result in unprofitable wells
The prices for natural gas have been quite unstable; a decline
in the
price could
Fluctuating market conditions and government regulations
may
the profitability of the
Environmental hazards involved in drilling gas wells may result
in
substantial liabilities for the
Increases in drilling costs would profitability
A reduced availability of drilling rigs
Failure by subcontractors to pay for materials or services could
Tax Status and Tax Risks
Partnership classification as a publicly traded
partnership
would substantially alter the tax treatment of the
tax liabilities may exceed the cash
distributions
received by
If the Service audits the tax returns, an might
owe
more taxes
Partnership losses after the conversion of general partnership
interests to limited partnership interests will be passive losses for tax
purposes
A material portion of the subscription proceeds will not be
currently
deductible
prepayment of drilling costs
Counsel's tax opinion does not cover various tax considerations
involved in one's investment in the
TERMS OF THE OFFERING
General
Activation of the Partnerships
Types of Units
Conversion of by the Managing General Partner and by
Unit Repurchase Program
Investor Suitability
ASSESSMENTS AND FINANCING
SOURCE OF FUNDS AND USE OF PROCEEDS
Source of Funds
Use of Proceeds
Subsequent Source of Funds
PARTICIPATION IN COSTS AND REVENUES
Profits and Losses; Cash Distributions
Revenues
Costs
Allocations Among Investor Partners; Deficit Capital Account
Balances
Cash Distribution Policy
Termination
COMPENSATION TO THE MANAGING GENERAL PARTNER AND AFFILIATES
PROPOSED ACTIVITIES
Introduction
Drilling Policy
Acquisition of Undeveloped Prospects
Title to Properties
PDC Prospects
Drilling and Completion Phase
Production Phase of Operations
Interests of Parties
Insurance
The Managing General Partner's Policy Regarding Roll-Up
Transactions
COMPETITION, MARKETS AND REGULATION
Competition and Markets
Natural Gas Pricing
Regulation
Proposed Regulation
MANAGEMENT
General Management
Experience and Capabilities as Driller/Operator
Petroleum Development Corporation
Certain Shareholders of Petroleum Development Corporation
Remuneration
Legal Proceedings
CONFLICTS OF INTEREST
Certain Transactions
FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNER
PRIOR ACTIVITIES
Prior Partnerships
Previous Drilling Activities
Payout and Net Cash Tables
Tax Deductions and Tax Credits of Participants in Previous
Partnerships
Partnership Estimated Proved Reserves and Future Net Revenues
TAX CONSIDERATIONS
Summary of Conclusions
General Tax Effects of Partnership Structure
Intangible Drilling and Development Costs Deductions
Classification of Costs
Timing of Deductions
Recapture of IDC
Depletion Deductions
Depreciation Deductions
Interest Deductions
Transaction Fees
Basis and At Risk Limitations
Passive Loss Limitations
Introduction
General Partner Interests
Limited Partner Interests
Alternative Minimum Tax
Gain or Loss on Sale of Property or Units
Partnership Distributions
Partnership Allocations
Profit Motive
Administrative Matters
Accounting Methods and Periods
Social Security Benefits; Self-employment Tax
State and Local Taxes
Individual Tax Advice Should Be Sought
SUMMARY OF LIMITED PARTNERSHIP AGREEMENT
Responsibility of Managing General Partner
Liabilities of General Partners, Including
Additional General Partners
Liability of Limited Partners
Allocations and Distributions
Voting Rights
Retirement and Removal of the Managing General Partner
Term and Dissolution
Indemnification
Reports to Partners
Power of Attorney
Other Provisions
TRANSFERABILITY OF UNITS
PLAN OF DISTRIBUTION
SALES LITERATURE
LEGAL OPINIONS
EXPERTS
ADDITIONAL INFORMATION
GLOSSARY OF TERMS
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
</TABLE>
SUMMARY
This . You should read the entire prospectus and the
attached appendices before you decide to invest.
Business of the Partnerships (page )
Each partnership will drill, own, and operate natural gas wells in
Colorado, Michigan, West Virginia, Pennsylvania, Utah and/or other states
and
will produce and sell gas from these wells. Of the offering proceeds
available
for drilling operations, we plan to utilize all proceeds in the
drilling
of development wells but may utilize up to 10% on one or more exploratory
wells.
See "Proposed Activities" (page ) .
The address and telephone number of the 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.
Investment Objectives (page )
This section discusses the investment objectives of the in
PDC
2003 Drilling Program. For reasons we discuss later in this summary and
prospectus under "Risk Factors," you may not realize some or all of the
benefits
discussed below. You should only invest in this if you can afford
the
loss of your entire investment.
The provides you with an opportunity to invest in the
drilling,
completion, and production of natural gas wells. The objective of the
investment
is to produce the following benefits for investors in the Program:
- Cash from the sale of natural gas
- A diversified investment in ten or more wells
87-89.5% of your investment .
- Accurate and timely reports, including Form K-1 tax information
distributed the first week of February.
The production from natural gas wells decreases as time passes, so
your
cash flow will also decrease over time. Natural gas prices change
constantly,
so your cash flow can also increase or decrease from month to month. Your
cash
distributions will be partially sheltered from taxes by depletion.
You may not receive some or all of these investment benefits for a
variety
of reasons including those discussed under "Risk Factors" later in the
prospectus.
Terms of the Offering (page )
The Program. PDC 2003 Drilling Program is a series of up to twelve
limited
partnerships to be formed under the West Virginia Uniform Limited
Partnership
Act. In this prospectus, we refer to each as a " or in the plural
as the
" We will offer and sell of the various during
2001,
2002 and 2003. See "Terms of the Offering" (page ) when formed
will
constitute a separate business entity. A limited partnership agreement will
govern the rights and obligations of the of each . We
attach
a form of the limited partnership agreement as Appendix A to the prospectus.
See
"Summary of Partnership Agreement" (page ) .
The Managing General Partner. The managing general partner of each
will be Petroleum Development Corporation, which we refer to in this
prospectus as the "Managing General Partner See "Management" (page
)
.
Units of Partnership Interest. You may choose to purchase units of
general
partnership interest or units of limited partnership interest in the
particular
being offered. "Unit" means a interest of a or of
an
purchased by an . This interest is the right and obligation
to
share a proportional part of the share of income, expense,
assets and liabilities. The fractional interest purchased by a one
unit
investment in the interest in the is the ratio of one
to
the total number of See "Terms of the Offering - Types of Units" (page
)
.
Funding of a Partnership. In order to fund a , we must sell
a
minimum of 75 units or $1,500,000 for each PDC designated as
an
-A,-B or -C Partnership, or a minimum of 125 or $2,500,000 for each
PDC
partnership designated as a -D Partnership. The maximum subscription
for
an -A, -B or -C Partnership is 750 or $15,000,000, and the maximum
subscriptions for a -D Partnership is 1,250 or $25,000,000. For
example, we must sell at least 75 or $1,500,000 to fund the PDC
2003-B
Limited Partnership and at least 125 or $2,500,000 to fund the PDC
2003-D
Limited Partnership. If you wish to see a table presenting the
minimum
and maximum subscriptions and the targeted offering termination and closing
date
for each , see "Terms of the Offering - General" (page ).
Subscription and Escrow. All subscriptions are payable in cash upon
subscription. We have selected Chase Manhattan Trust Company as
escrow
agent to hold all subscription proceeds of each in a separate
interest-bearing escrow account. See "Terms of the Offering" (page
) .
Conversion of Units by the Managing General Partner and by Additional
General Partners. We will convert all of general partnership
interest
of a particular of limited partnership interest of that
upon
completion of drilling and completion operations of that of limited
partnership interest . See "Terms of the Offering - Conversion
of
Units by the Managing General Partner and by Additional General Partners"
(page
), "Proposed Activities - Insurance" (page ), and "Tax Considerations
-
Conversion of Interests" (page ) .
Unit Repurchase Program. Beginning with the third anniversary of the
date
of the first cash distribution of the particular of that
may
offer their to us for repurchase. Repurchase of is
subject to
our financial ability to purchase the . See "Terms of the
Offering - Unit Repurchase Program" (page ) and "Tax Considerations - Gain
or
Loss on Sale of Property or Units" (page ) .
Suitability Standards - Long_Term Investment. We have instituted
strict
suitability standards for investment in the . You may not invest
unless
you satisfy the suitability requirements. See "Terms of the
Offering -
Investor Suitability" (page ) .
Risk Factors. This offering involves numerous risks, including the
risks
associated with gas and oil drilling and investments in gas and oil drilling
programs, unlimited liability as an , lack of a trading market in
the
, and significant tax considerations. See "Risk Factors" (page ) and
"Tax
Considerations" (page ). You should carefully consider the significant
risk
factors inherent in and affecting the business of the and this
offering
before making an investment.
Compensation of the Managing General Partner (page )
We and our affiliates will receive substantial compensation upon the
formation and as a result of the operation of the will receive a
one-time
management fee equal to 2.5% of the aggregate subscriptions upon of
each
, fees for drilling and operating wells, for marketing the
natural gas produced by wells, and for administering the ,
and
commissions and fees for selling the to the Managing General Partner
and
Affiliates" (page ) .
Participation in Costs and Revenues (page )
Generally, will receive 80% and the Managing General Partner
will
receive 20% of profits and losses throughout the term of each
.
The interests of the and us could also change if we invest additional
funds
for tangible drilling and lease costs. See "Participation in Costs and
Revenues
- Revenues - Revisions to Sharing Arrangements" (page ) and " - Costs -
Lease
Costs, Tangible Well Costs, and Gathering Line Costs" (page ). In
Application of Proceeds (page )
We estimate that we will apply the proceeds from the aggregate funding
of
a , after our cash contribution, as follows. See "Source of Funds
and
Use of Proceeds" (page ).
<TABLE>
<C> <C>
Percentage of Total
Activity Capital Contributions
Drilling and Completion Costs 89.3%
Organization and Offering Costs 8.6%
Management Fee 2.1%
Total 100.00
</TABLE>
Tax Considerations; Opinion of Counsel (page )
Duane, Morris & Heckscher LLP has issued to us its opinion, concerning
all
material federal income tax issues applicable to an investment in the
.
See "Tax Considerations" (page ) . To fully understand these tax
issues, you should read the tax opinion in Appendix D.
Rights of the Investor Partners (page )
The limited partnership agreement, which we attach to this prospectus
as
Appendix A, sets forth your rights as an . For a summary of your
rights, see "Summary of Limited Partnership Agreement."
RISK FACTORS
Investment in the 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. As a prospective investor, you should
consider
carefully the following factors, in addition to the other information in
this
prospectus, prior to making your investment decision.
Special Risks of the Partnerships
Drilling natural gas wells is speculative, may be unprofitable, and
may
result in the total loss of your investment . The drilling and completion
operations to be undertaken by each of the for the development of
natural gas reserves are speculative and involve the possibility of a total
loss
of your investment in a . Drilling activities may be unprofitable,
not
only from non-productive wells, but also 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 ) .
The Managing General Partner has not selected any prospects for
acquisition, and as a result the will be unable to evaluate any
prospect
before they invest in the . We have not selected any prospect for
acquisition by any and will not select prospects for a particular
until after the activation of that . You will not have an
opportunity before purchasing to evaluate for yourself the relevant
geophysical, geological, economic or other information regarding the
prospects
to be selected. See "Proposed Activities - Acquisition of Undeveloped
Prospects" (page ) .
Because of a lengthy offering period, delays in the investment of an
investor's subscription are likely . Upon execution and delivery by you,
your
subscription will be irrevocable and cannot be withdrawn. Because the
offering
period for a particular can extend months, delays in the investment of
proceeds from your initial subscription date are likely. See "Terms of
the
Offering
will be individually liable for obligations and liabilities beyond
the
amount of their subscriptions, assets, and the assets of the Managing
General
Partner . Under West Virginia law, the state in which each will
organize, general partners of a partnership have unlimited liability with
respect
to that partnership 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 operations. If you invest as
an
, you may be liable for amounts in excess of your subscriptions, the
assets
of the , including insurance coverage, and the assets of the
Managing
General Partner .
The Managing General Partner and its will receive
compensation
from the upon funding of the and throughout the life of the
. We will receive compensation throughout the life of the . See
"Compensation to the Managing General Partner and Affiliates" (page )
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. We cannot predict whether any prospect will
produce
natural gas or commercial quantities of natural gas. We 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. See "Proposed
Activities - Acquisition of Undeveloped Prospects" (page )
Sufficient insurance coverage may not be available for the partnership,
thereby
increasing the risk of loss for the investor partners insurance
coverage
which the has available may become unavailable or prohibitively
expensive.
In case, we may elect to change the insurance coverage. See
"Proposed Activities - Insurance" (page ) could be exposed to
additional financial risk due to the reduced insurance coverage and due to
the
fact that would continue to be individually liable for obligations
and
liabilities of the As an , you could be subject to
greater
risk of loss of your investment since less insurance would be available to
protect your from casualty losses.
A which drills fewer wells will be less diversified, thereby
increasing the risk of financial loss for the investors . We intend to
spread
the risk of natural gas drilling by participating in wells on a number of
different prospects. However, the cost of drilling wells in different
geographic
locations varies greatly. A subscribed at the minimum level or
which
drills more expensive wells would be able to participate in fewer prospects,
the diversification of the investment in prospects and
your
risk of financial loss of that . See "Proposed Activities -
Drilling
and Completion Phase - Drilling and Operating Agreement" (page ) .
Through their involvement in partnership and other non_
activities, the Managing General Partner and its have interests
which
conflict with those of the . Our continued active participation
in oil
and gas activities for our own account and on behalf of other partnerships
organized or to be organized by us, our sale of leases to and other
transactions
with the , and the manner in which revenues are allocated
create conflicts of interest with the . We have interests which
inherently conflict with your interests. . See "Conflicts of Interest"
(page ) .
Unaffiliated persons might manage jointly_owned prospects;
a
could be financially liable for obligations of jointly_owned
prospects 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 might purchase less than a 50%
working interest in one or more prospects. As a result, someone other than
the
or us may control and manage prospects. A
partnership
could be held liable for the joint activity obligations of the other working
interest owners, 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. As a result,
. See "Proposed Activities - Drilling and Completion Phase - Drilling
and
Operating Agreement" (page ) may not borrow funds, even if needed
for
partnership operations; as a result, the partnership might not
have
sufficient capital for its operations 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 time as there is production from partnership well
operations.
The limited 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 ) and "Proposed Activities - Production Phase of Operations -
Expenditure
of Production Revenues" (page ) and other partnerships sponsored
by the
Managing General Partner may compete with each other for prospects,
equipment,
contractors, and personnel; as a result, the partnership may find it
more
difficult to operate effectively . During and , we
plan
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
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 our personnel, the fact that partnerships
previously
organized by us 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
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 your 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.
See "Proposed Activities" (page ) .
The results of drilling previous partnerships sponsored by the
Managing
General Partner are not indicative of the results to be experienced by the
partnerships should not consider information concerning the prior
drilling experience of previous partnerships sponsored by us, presented
under the
caption "Prior Activities" (page ), as being indicative of the results you
might expect from your investment in these partnerships
In view of the cost sharing arrangements, the will bear the
substantial amount of costs and risks of non_commercial wells . Under the
cost
and revenue sharing provisions of the limited partnership agreement, we and
the
investor partners may share in costs disproportionate to our
respective
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. See "Participation
in
Costs and Revenues" (page ) may be personally liable the
limited partnership agreement. As an investor partner , you may not
participate in the management of partnership business. The limited
partnership agreement forbids you as an investor partner from acting
in
a manner harmful to the business of the partnership If you
the
terms of the limited partnership agreement, you may have to pay for
losses and may also have to pay other for all damages resulting
from
your breach of the limited partnership agreement. See "Summary of Limited
Partnership Agreement" (page ) by the Managing General Partner
could
reduce the value of the partnership and the investment interests of
the
investor partners We have agreed
to
indemnify each of the for obligations related to casualty and
business
losses which exceed available insurance coverage and partnership
assets.
Any successful claim of indemnification reduce the value of the
partnership . As a result, the value of your investment interest in
the
partnership would be reduced. In event , you could lose
your
entire investment in the partnership . See "Summary of Partnership
Agreement - Indemnification" (page ) distributions could result in
liability of receive a return of any part of their capital
contributions to
a partnership , without violation of the limited partnership agreement
or
the West Virginia Uniform Limited Partnership Act, will be liable
to the
partnership for a period of one year after return for the
amount
of the returned contributions. If the return is in violation of the limited
partnership agreement or the Act, the will be liable to the
partnership for a period of six years after return for the
amount
of the contribution wrongfully returned.
A significant financial loss by the Managing General Partner could
. As a result of our commitments as general partner of several
partnerships
and because of the unlimited liability of a general partner to third
parties, our
net worth is at risk of reduction if we suffer a significant financial loss.
Because we are primarily responsible for the conduct of the
partnership's
affairs, a significant adverse financial reversal for us could . See
"Prior
Activities - Prior Partnerships" (page ) distribution if the
distribution
would cause a capital account deficit. The limited partnership agreement
prohibits you from receiving allocations or distributions to the
extent
would create deficits in your capital account.
The dealer manager is not independent and has not conducted an
independent
due diligence evaluation of the offering . PDC Securities Incorporated, the
of this offering, is our affiliate and is not independent which creates
a
conflict of interest in its due diligence examination and evaluation of this
offering.
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. You 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.
See "Proposed Activities" (page ) .
The prices for natural gas have been quite unstable; a decline in the
price
could . Global economic conditions, political conditions, and
energy
conservation have created unstable prices. Revenues of each
partnership
are directly related to natural gas prices which we cannot predict. The
prices
for domestic natural gas production have varied substantially over time and
may
in the future . Prices for natural gas have been and are likely to
remain
extremely unstable. See "Competition, Markets and Regulation" (page )
.
Fluctuating market conditions and government regulations may
the profitability of the partnership . The sale of any natural
gas
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 ) .
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 may be
subject to liability for pollution, abuses of the environment and other
similar
damages. 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. See
"Proposed
Activities - Insurance" (page ) .
Increases in drilling costs would profitability . The oil
and gas
industry historically has experienced periods of rapid cost increases.
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 .
A reduced availability of drilling rigs . 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 the timing of investors' tax deductions. See
"Competition, Markets and Regulation - Competition and Markets" (page )
.
Failure by subcontractors to pay for materials or services could
profitability . 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
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 a
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
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 ) .
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. opinion is not binding on the Internal
Revenue Service or the courts. The Service could assert that a
partnership should be classified as one of these other structures.
If a
partnership were so classified, any income, gain, loss, deduction,
or
credit of the partnership would remain at the entity level, and not
flow
through to you, the income of the partnership would be subject to
corporate tax rates at the entity level and distributions to you 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 ) may not be advisable for a
person
who does not anticipate having substantial current taxable income
from
passive activities. losses generated by the and
allocable to will be subject to the passive activity rules not
be
subject to the passive activity rules Under the Code, a partner's
tax
liabilities may exceed the cash distributions received by . Federal
income tax payable by you by reason of your distributive share of
partnership taxable income for any year may exceed the cash
distributed
to you by the partnership . You must include in your own return for
a
taxable year your 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 you. For example, income from the
partnership's
sale of gas production is taxable to you as ordinary income subject to
depletion
and other deductions; your distributive share of the partnership's
taxable
income will be taxable to you whether or not the income is actually
distributed
to you.
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 audits occur, tax
adjustments might be made that would increase the amount of taxes due or
increase
the risk of audit of your individual tax return. In addition, costs and
expenses
may be incurred by a partnership in contesting adjustments.
The
cost of responding to audits of your tax return will be borne solely by you.
See
"Tax Considerations - Administrative Matters" (page ) .
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 will not be subject to the
passive
activity rules. However, will be subject to the passive
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 ) prepayment of drilling costs. Some
drilling
cost expenditures may be made as prepayments during 2001 (with respect to
partnerships designated as "PDC 2001- Limited Partnership"), 2002
(with
respect to partnerships designated as "PDC 2002- Limited
Partnership"),
and 2003 (with respect to partnerships designated as "PDC 2003-
Limited
Partnership") for drilling and completion operations which in large part may
be
performed during 2002, 2003 and 2004, respectively. All or a portion of
prepayments may be then currently deductible by the applicable
partnership if the well to which the prepayment relates is spudded
within
90 days after December 31, 2001, 2002 or 2003, respectively; the payment is
not
a mere deposit; and the payment serves a business purpose or otherwise
satisfies
the clear reflection of income rule. A could fail to satisfy the
requirements for deduction of prepaid intangible drilling and development
costs.
The Service may challenge the deductibility of these prepayments.
If
challenge were successful, 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 ) .
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:
- 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,
- whether any of the partnership's properties
will
be entitled to percentage depletion,
- whether any interest incurred by a with
respect
to any borrowings will be deductible or subject to limitations on
deductibility,
- whether the fees to be paid to us and to third
parties
will be deductible, and
- 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.
You should recognize that an opinion of counsel merely represents
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.
TERMS OF THE OFFERING
General
- Up to twelve limited partnerships (four in 2001,
four in
2002, four in 2003)
- Units of general partnership interest and
units
of limited partnership interest being offered - investor must choose
- $20,000 per
- Minimum subscription - $5,000
- Minimum partnership - $1,500,000 in
- Maximum partnership - $15,000,000 in
- Maximum aggregate subscriptions for twelve
partnerships
- $150,000,000
- Subscription proceeds will be placed in escrow until
partnership funded.
PDC 2003 Drilling Program will offer for sale an aggregate of 7,500
Units
at $20,000 per , aggregating $150,000,000, of preformation interests
in
a series of up to twelve limited partnerships to be formed under the laws
of West
Virginia. You may purchase units only if you meet the suitability
standards set forth below. We will offer units for sale over a
three-year
period. The managing general partner of each partnership will be
Petroleum Development Corporation, a publicly-owned Nevada
corporation .
We in our discretion may accept subscriptions for less than full
units . The minimum subscription is one-quarter ($5,000).
In
the event you purchase 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). We will not sell units to tax-exempt investors
or to
foreign investors.
You may elect to purchase units as an or as a .
Additionally, you may purchase units of general partnership interest
and
units of limited partnership interest.
Upon the sale of at least the minimum number of units in a
partnership (75 units aggregating $1,500,000; 125 units
aggregating $2,500,000 with respect to each of PDC 2001-D Limited
Partnership,
PDC 2002-D Limited Partnership and PDC 2003-D Limited Partnership) and upon
termination of the offering of units in that partnership , we
will
form a limited partnership under the laws of West Virginia. At that time
the
units of preformation general partnership interest and preformation limited
partnership interest will become units of general partnership
interest and
units of limited partnership interest, respectively, in the
particular
partnership . There is no restriction on the composition of the type
of
partnership interests with respect to any partnership .
If we do 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 , we 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 escrowed funds and without any deduction from the escrowed funds.
We 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,
we will send to each investor a confirmation of the purchase.
The maximum subscription of any partnership will be the lesser
of
$15,000,000 ($25,000,000 with respect to each of PDC 2001-D Limited
Partnership,
PDC 2002-D Limited Partnership and PDC 2003-D Limited Partnership) or the
remaining unsold units based on the $150,000,000 aggregate registration.
We will designate the various partnerships as follows. The
subscription period for each of the partnerships in our will
be
as follows, unless earlier terminated or withdrawn by us:
<TABLE>
<C> <C> <C> <C>
Partnership Minimum Maximum Planned
Name Subscription Termination
PDC 2001-A $1.5 million $15 million May , 2001
PDC 2001-B $1.5 million $15 million September ,
2001
PDC 2001-C $1.5 million $15 million November ,
2001
PDC 2001-D $2.5 million $25 million December 31, 2001
We will offer and sell the securities of these partnerships only
during
2001.
PDC 2002-A $1.5 million $15 million May 13, 2002
PDC 2002-B $1.5 million $15 million September 9, 2002
PDC 2002-C $1.5 million $15 million November 11, 2002
PDC 2002-D $2.5 million $25 million December 31, 2002
We will offer and sell the securities of these partnerships only
during
2002.
PDC 2003-A $1.5 million $15 million May 19, 2003
PDC 2003-B $1.5 million $15 million September 8, 2003
PDC 2003-C $1.5 million $15 million November 10, 2003
PDC 2003-D $2.5 million $25 million December 31, 2003
</TABLE>
We will offer and sell the securities of these partnerships only
during
2003.
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 2001-
Limited Partnership," "PDC 2002- Limited Partnership" or "PDC 2003- Limited
Partnership" may extend beyond December 31, 2001, 2002, or 2003,
respectively.
Although the offering of units in subsequent
partnerships
will not commence until the subscription of units in prior
partnerships has reached the minimum subscription or that prior
offering
has terminated, we may choose to offer the units of PDC 2001-C
Limited
Partnership and PDC 2001-D Limited Partnership (and PDC 2002-C Limited
Partnership and PDC 2002-D Limited partnership; and PDC 2003-C Limited
Partnership and PDC 2003-D Limited Partnership, as appropriate) at the same
time
until the offering of units in PDC 2001-C Limited Partnership (or PDC
2002-C Limited Partnership or PDC 2003-C Limited Partnership, as
appropriate) 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, we will not offer or sell additional units with respect to
that
partnership . At or about the time of funding of a particular
partnership , we anticipate that we will supplement this prospectus
to
reflect the results of the offering of . We will not commence
operations of a particular partnership until termination of its
offering
period.
We will fund each partnership promptly following the
termination of
its respective offering period, provided that has reached the
minimum
subscriptions. We will not fund any partnership beyond December 31,
2001,
with respect to partnerships designated "PDC 2001- Limited
Partnership,"
beyond December 31, 2002, with respect to partnerships designated
"PDC
2002-Limited Partnership" and December 31, 2003, with respect to
partnerships designated "PDC 2003- Limited Partnership."
Subscriptions for units are payable $20,000 in cash per
purchased upon subscription. We will place all subscription
proceeds of each partnership in a separate interest-bearing escrow
account
with our escrow agent, Chase Manhattan Trust Company, located at One Oxford
Centre, Suite 1100, 301 Grant Street, Pittsburgh, Pennsylvania 15219,
during the
offering period of that 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 us and the dealer
manager. At that time the escrow agent will disburse the escrowed
subscriptions
in accordance with these instructions. In the event that we fail to
raise
the minimum subscriptions, the escrow agent will promptly return the
escrowed
funds to the subscribers.
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 .
However, if the offering of units in PDC 2001-C Limited Partnership
or PDC
2001-D Limited Partnership (or PDC 2002-C Limited Partnership or PDC 2002-D
Limited Partnership; or PDC 2003-C Limited Partnership or PDC 2003-D Limited
Partnership, as appropriate) has not closed on or before December 31, 2001
(or
2002 or 2003, as appropriate), the escrow agent will promptly return the
escrowed
funds of that particular partnership to those investors. The escrow
agent
will not commingle subscriptions with our funds, nor will subscriptions be
subject to the claims of our 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. We will direct the escrow
agent
to pay to the respective subscriber after closing any interest accrued on
subscription funds prior to closing of the offering and funding of a
partnership .
Investors should make their checks for units payable to "Chase
as
Escrow Agent for PDC 2001- Limited Partnership" (or "PDC 2002- Limited
Partnership" or "PDC 2003- Limited Partnership," as appropriate) and give
their
checks to their broker for submission to the and escrow agent.
Your
execution of the subscription agreement and its acceptance by us constitute
your
execution of the limited partnership agreement and your agreement to be
bound by
the terms of the limited partnership agreement as a , including
your
granting of a special power of attorney to us appointing us as your lawful
representative to execute and file a certificate of limited partnership and
any
amendment of the certificate, 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.
We will organize each partnership under the Act and each
partnership will receive funds promptly following the termination of
its
offering period. However, we will not fund a partnership with less
than
the requisite minimum aggregate subscriptions. A partnership will
not
commence any drilling operations until after its funding.
Each partnership will be a separate and distinct business and
economic entity from each other partnership . Thus, as an investor
partner , you will be a only of that partnership in which
you
specifically invest and will have no interest in any of the other
partnerships (unless you also invest in other partnerships .
Therefore, you should consider and rely solely upon the operations and
success
(or lack of success) of your own partnership in assessing the quality
of
your investment.
Upon funding of a partnership , we will deposit the subscription
funds in interest-bearing accounts or invest 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.
We anticipate that within 12 months following the formation of a
partnership it will have expended or committed all subscriptions for
partnership operations. We will return any unexpended and/or
uncommitted
subscriptions at the end of 12-month period pro rata to the
investor
partners and we will reimburse 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.
We 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. We will also take all other actions necessary to
qualify the partnerships to do business as limited partnerships or
cause
the limited partnership status of the partnerships to be recognized
in any
other jurisdiction where the partnerships conduct business.
Types of Units
- Investor may choose to be .
You may purchase units in a partnership as a
or as
an 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 these activities.
Further, 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. See
"Tax
Considerations
You may transfer or assign your units of partnership interest
in
accordance with Section 7.03 of the limited partnership agreement.
Transferees
seeking to become substituted partners must meet the suitability
requirements set forth in this prospectus. A substituted will have
the
same rights and responsibilities, including unlimited liability, in the
partnership as every other . See "Risk Factors - Unlimited
Liability of Additional General Partners
You must indicate on the investor of the subscription
agreement the
number of limited partnership units or general partnership
units
subscribed for. If you fail to indicate on the subscription agreement a
choice
between investing as a limited partner or as an additional general
partner , we will not accept your subscription but will promptly return
the
subscription agreement and the tendered subscription funds to you.
Limited Partners. The limited partners will consist of the
,
Steven R. Williams, one of our executive officers and directors, until
the
admission of a limited partner to the partnership , and each
investor who purchases units of limited partnership interest being
offered
. The liability of a limited partner of the
partnership
for the partnership's debts and obligations will not exceed that
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 for the amount of his or her returned contribution if a
limited
partner has received the return without violation of the limited
partnership
agreement or the West 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 for the amount
of
the contribution wrongfully returned if a limited partner has
received the
return in violation of the limited partnership agreement or the Act.
General Partners. The will consist of the and each
investor purchasing units of general partnership interest. We refer
to
these persons in this prospectus as " As a general partner of a
partnership 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 us,
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 us which we discuss 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
- We will convert all units of general partnership interest
into
units of limited partnership interest after drilling and completion
operations are done.
- If there is a material change in a partnership's
insurance
coverage, additional general partners may convert prior to
change.
- Liability for investors will be limited
after
conversion.
We 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 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 us of intent to
convert.
Conversion of an additional general partner in a particular
partnership will be effective upon our filing an amendment to the
Certificate of Limited Partnership. We are obligated to file an amendment
to the
Certificate at any time during the full calendar month after receipt by us
of the
required notice of the additional general partner , provided that the
conversion will not constitute a termination of the partnership for
tax
purposes. A conversion made in response to a material change in that
partnership's insurance coverage will be effective prior to the
effective
date of the change in insurance coverage. After the conversion of a
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 the conversion, but will have limited liability to the same
extent
as limited partners after conversion to limited partner status
is
effected.
We are not entitled to convert our 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, 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 units which aggregate 10% of the initial
subscriptions,
subject to its financial ability to do so and opinions of counsel.
Beginning with the third anniversary of the date of the first cash
distribution of the particular partnership , you may tender your
units to us for repurchase. Subject to the available borrowing
capacity
under our loan agreements to effect repurchases and the opinion of counsel
referred to below, each year we will offer to repurchase for cash a minimum
of
10% of the units originally subscribed to in the particular
partnership . Our offers to purchase units will, however, be
conditioned on the receipt of an opinion of our counsel that the
consummation of
offer will not cause the partnership to be treated as a
"publicly
traded partnership" for purposes of Code Section 7704 and on
counsel's
determination that the repurchases of a particular investor partner's
will
not result in the termination of the partnership for federal income
tax
purposes. It is possible that repurchases of units could result in
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
possibility
of characterization, we will require receipt of counsel's opinion.
We will not favor one particular partnership over another in
the
repurchase of units . We will extend offer equally to all
interest holders participating in an individual partnership ,
excluding
interests held by us. Notwithstanding the preceding sentence, if
investor
partners tender more than 10% of the units from a
partnership
or more units than we are able to purchase, we will purchase
units
on a "first-come, first-served" basis based on date of receipt by us of a
letter
of acceptance of the repurchase offer from the investor partner .
To the
extent that we are unable to repurchase all units tendered, because
of
limitations imposed by the or due to insufficient borrowing
capacity
under any loan banking agreement(s) to which we may be a party, a tendering
investor partner will be entitled to have his or her units
repurchased on a "first-come, first-served" basis, regardless of
partnership , provided that the repurchase of a particular investor
partner's will not have the effect of causing termination of his or her
partnership for tax purposes or of causing the partnership to
be
treated as a "publicly traded partnership." To the extent that we are
unable to
repurchase all units tendered at the same time by partners of
any
partnership , we will repurchase those particular units on a
pro
rata basis.
In order to initiate the process we will repurchase your
units , you must provide us written notification of your intention to
have
us purchase your units . We will provide you a written offer of a
specified price for purchase of the particular units within 30 days
of our
receipt of the written notification. Upon receipt of the repurchase price
established by us, you, if in fact you elect to accept the repurchase price,
need
to notify us in writing that price is acceptable. We will promptly
mail
you a check for the proceeds of the purchase.
The minimum offer which we 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 we have received the written notification referred to above. We
may,
in our sole and absolute discretion, increase the offer for interests
tendered
for sale.
An offering price established by us may not represent the fair market
value
of the units . In setting the offering price, we wilunitl consider
our
available funds and our desire to acquire production as represented by the
unit and will take into account what we perceive to be our own best
interests as a publicly-owned company. You are free to accept or not to
accept
the offer from us;
you are in no way obligated to accept our offer. We will provide you with
detailed information as to how we calculated our offer. We 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 with SEC Regulation S-X, Article 4, Rule 4-10. This calculation
will
take into account our 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 1,157 units (out of approximately 6,098
eligible
units) of prior programs sponsored by us 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 include 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
us from 1984 through 1996.
Investor Suitability
- Investment in the units involves a high
degree of
risk.
- You may invest only if you are qualified to 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 in this section.
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. We will not sell units to
tax-exempt investors or to foreign investors.
We will sell units, including fractional units , to you
only
if you satisfy the following suitability requirements. Net worth will be
determined exclusive of home, home furnishings and automobiles. In
addition, we
will sell units to you only if you make a written representation that
you
are the sole and true party in interest and that you are not purchasing for
the
benefit of any other person (or that you are purchasing for another person
who
meets all of the conditions set forth in this section).
The following represent footnotes to various states set forth in the
two
following tables. Please refer to the following footnotes as appropriate.
(a) California residents generally may not transfer
units without the consent of the California Commissioner of
Corporations.
(b) Michigan, New Mexico, Ohio, Pennsylvania, and
South
Dakota investors may not invest if the dollar amount of their investment is
equal
to or more than 10% of their net worth.
(c) 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 Units of Limited Partnership Interest. If you wish to
purchase units of limited partnership interest in the
partnership ,
you must satisfy the following suitability requirements for your state of
residence, as summarized in the following table and accompanying footnotes.
Error! Reference source not found.State
AK
AL AR AZ
CA
CO CT DC DE
FL GA HI IA
ID IL IN KS
KY LA MA MD
ME MN MS
MI
Requirement
2
1
4 (a)
1
1
1
1
1
5 (b)
State
MO
MT
NC
ND NE
NH
NJ
NM
NV NY
OH
Requirement
1 (c)
1
5
1
3
1
1 (b)
1
1 (b)
State
OK OR
PA
RI SC
SD
TN TX UT VA
VT WA WI WV
WY
Requirement
1
6 (b)
1
5 (b)
1
1
1
The following footnotes relate to the corresponding numbers in the table
above.
(1) You must 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
you 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 .
(2) You must be a person whose total purchase does not
exceed
5% of your net worth if the purchase of securities is at least $10,000, and
have
either: 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 a minimum net worth of $225,000, exclusive of
principal
automobile, principal residence, and home furnishings.
(3) You must have either: a net worth of not
less
than $250,000 (exclusive of home, furnishings, and automobiles), or
a net
worth of not less than $125,000 (exclusive of home, furnishings, and
automobiles), and $50,000 in taxable income.
(4) You must have net worth of not less than
$250,000
(exclusive of home, furnishings, and automobiles) and expect to have gross
income
in 2001 (with respect to investments in the PDC 2001 designated
partnerships ) or in 2002 (with respect to the PDC 2002 designated
partnerships ) or in 2003 (with respect to the PDC 2003 designated
partnerships ) of $65,000 or more, or have net worth of not
less
than $500,000 (exclusive of home, furnishings, and automobiles), or
have
net worth of not less than $1,000,000, or expect to have gross
income in
2001 (with respect to investments in the PDC 2001 designated
partnerships )
or in 2002 (with respect to the PDC 2002 designated partnerships ) or
in
2003 (with respect to the PDC 2003 designated partnerships ) of not
less
than $200,000.
(5) You must have a net worth of not less than
$225,000 (exclusive of home, furnishings, and automobiles), or a net
worth of not less than $60,000 (exclusive of home, furnishings, and
automobiles)
and estimated 2001 (with respect to investments in the PDC 2001 designated
partnerships or in 2002 (with respect to the PDC 2002 designated
partnerships or in 2003 (with respect to the PDC 2003 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 .
(6) You must have either: a net worth of at
least
$225,000 (exclusive of home, furnishings, and automobiles); or a net
worth of at least $60,000 (exclusive of home, furnishings, and automobiles)
and
taxable income of $60,000 or more in 2000 (for the PDC 2001 designated
partnerships ; in 2001 for the PDC 2002 designated
partnerships ; in
2002 for the PDC 2003 designated partnerships , or estimate that your
2001
(for the PDC 2001 designated partnerships ; 2002 for the PDC 2002
designated partnerships ; 2003 for the PDC 2003 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 or
that you are purchasing in a fiduciary capacity for a person or entity
who
satisfies the requirements of or .
Purchasers of Units of General Partnership Interest. If you wish to
purchase units of general partnership interest in the
partnership ,
you must satisfy the following suitability requirements for your state of
residence, as summarized in the following table.
State
AK
AL AR
AZ
CA
CO CT DC
FL GA HI
IA
ID IL
IN KS KY
LA
MA
Requirement
2
4
5
6 (a)
1
1
5
1
5
1
4
State
MD
ME MN MS
MI
MO
MT
NC
ND NE
NH
NJ
NM
NV NY
Requirement
1
4
5 (b)
5 (c)
1
4
1
3
1
5 (b)
1
State
OH
OK OR
PA
RI SC
SD
TN TX
UT VA
VT WA
WI WV WY
Requirement
5 (b)
5
4 (b)
1
1 (b)
4
1
5
1
The following footnotes relate to the corresponding numbers in the table
above.
(1) You must 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
you 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 .
(2) You must be a person whose total purchase does not
exceed
5% of your net worth if the purchase of securities is at least $10,000, and
have
either: 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 a minimum net worth of $225,000, exclusive of
principal
automobile, principal residence, and home furnishings.
(3) You must have either: a net worth of not
less
than $250,000 (exclusive of home, furnishings, and automobiles), or
a net
worth of not less than $125,000 (exclusive of home, furnishings, and
automobiles), and $50,000 in taxable income.
(4) You must have an individual or joint minimum
net
worth (exclusive of home, home furnishings and automobiles) with your spouse
of
$225,000, without regard to the investment in the and a combined
minimum
gross income of $100,000 or more for the current year and for the two
previous
years; or an individual or joint minimum net worth with your spouse
in
excess of $1,000,000, inclusive of home, home furnishings and automobiles;
or
an individual or joint minimum net worth with your spouse in excess of
$500,000, exclusive of home, home furnishings and automobiles; or a
combined minimum gross income in excess of $200,000 in the current year and
the
two previous years.
(5) You must have an individual or joint minimum
net
worth (exclusive of home, home furnishings, and automobiles) with your
spouse of
$225,000, without regard to an investment in the , 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 an individual
or
joint minimum net worth with your spouse in excess of $1,000,000, inclusive
of
home, home furnishings and automobiles; or an individual or joint
minimum
net worth with your spouse in excess of $500,000, exclusive of home, home
furnishings and automobiles; or a combined minimum gross income in
excess
of $200,000 in the current year and the two previous years.
(6) You must have net worth of not less than
$250,000
(exclusive of home, furnishings, and automobiles) and expect to have gross
income
in 2001 (with respect to investments in the PDC 2001 designated
partnerships or in 2002 (with respect to the PDC 2002 designated
partnerships or in 2003 (with respect to the PDC 2003 designated
partnerships of $120,000 or more, or have net worth of not
less
than $500,000 (exclusive of home, furnishings, and automobiles), or (c
have net worth of not less than $1,000,000, or ( expect to have
gross
income in 2001 (with respect to investments in the PDC 2001 designated
partnerships or in 2002 (with respect to the PDC 2002 designated
partnerships or in 2003 (with respect to the PDC 2003 designated
partnerships of not less than $200,000.
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 limited 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 you purchase units in a fiduciary capacity for any other
person (or for an entity in which you are deemed to be a "purchaser" of the
subject units all of the suitability standards set forth above will
be
applicable to other person.
You are required to execute your own subscription agreements. We will
not
accept any subscription agreement that has been executed by someone other
than
you or in the case of fiduciary accounts by someone who does not have the
legal
power of attorney to sign on your behalf.
For details regarding how to subscribe, see "Instructions to
Subscribers"
which we attach 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.
We intend to develop a particular partnership's interests in
its
prospects only with the proceeds of subscriptions and our capital
contributions.
However, these funds may not be sufficient to fund all costs
and
it may be necessary for a partnership to retain partnership
revenues for the payment of these costs, or for us to advance the
necessary funds to a partnership . We will not drill any wells beyond
the
initial wells. Additional development refers to work necessary or desirable
to
enhance production from existing wells. We will retain payment for
development work from partnership proceeds in one of two methods:
(a) We will prepare an 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) We will prepare an estimate for 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 we will pay the operator as the work progresses.
The choice of which option to use will be at our discretion, based on the
amount
of the anticipated expenditure and the urgency of the necessary work.
Generally,
we will elect option (a) for emergency and expenditures of less than $10,000
and
option (b) for expenditures of $10,000 and greater.
The limited 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 limited partnership agreement.
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; $2,500,000 ranging to $25,000,000 for
each
of PDC 2001-D Limited Partnership, PDC 2002-D Limited Partnership and PDC
2003-D
Limited Partnership) and our contribution in cash ($326,250 ranging to
$3,262,500; $543,750 ranging to $5,437,500 for each of PDC 2001-D Limited
Partnership, PDC 2002-D Limited Partnership and PDC 2003-D Limited
Partnership)
for a total amount of $1,826,250 for sale of 75 units ranging to
$30,437,500 for sale of 1,250 units .
Use of Proceeds
The following table presents information respecting the financing of
a
partnership in four different circumstances:
- sale of 750 units ($15,000,000), the
maximum number of units for any partnership , designated as PDC
2001
[or 2002 or 2003]-A, -B, or -C Limited Partnership,
- sale of 75 units ($1,500,000) the
minimum
for any partnership designated as PDC 2001 [or 2002 or 2003] -A, -B,
or
-C Limited Partnership,
- sale of 1,250 units ($25,000,000),
the
maximum for any -D designated partnership , and
- sale of 125 units ($2,500,000), the
minimum for any -D designated partnership .
In the table below, the percentages below are based upon total
investor
partners' capital contributions and our capital contribution. Each of the
partnerships designated as PDC 2001-A through -C Limited Partnership, PDC
2002-A
through -C Limited Partnership, and PDC 2003-A through -C Limited
Partnership may
sell a maximum of 750 units ($15,000,000) and must sell a minimum of
75
units ($1,500,000). Each of the partnerships designated PDC 2001-D
Limited Partnership, PDC 2002-D Limited Partnership, and PDC 2003-D Limited
Partnership may sell a maximum of 1,250 units ($25,000,000) and must
sell
a minimum of 125 units ($2,500,000).
The following table reflects that PDC Securities Incorporated, our
affiliate, may reallow in whole or in part up to $1,500,000 (for the sale
of 750
units; a maximum of $2,500,000 for each of PDC 2001-D Limited Partnership,
PDC
2002-D Limited Partnership and PDC 2003-D Limited Partnership for the sale
of
1,250 units) ranging to $150,000 (for the sale of the minimum number of
units;
a minimum of $250,000 for each of PDC 2001-D Limited Partnership, PDC 2002-D
Limited Partnership, and PDC 2003-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; these fees will range from $7,500 for the
sale
of the minimum number of units ($12,500 for each of PDC 2001-D Limited
Partnership, PDC 2002-D Limited Partnership, and PDC 2003-D Limited
Partnership)
ranging to $75,000 for the sale of the maximum number of units ($125,000 for
each
of PDC 2001-D Limited Partnership, PDC 2002-D Limited Partnership, and PDC
2003-D
Limited Partnership). These payments will be made in cash solely on the
amount
of initial subscriptions.
The table also reflects that we will pay organization and offering
costs
in excess of 10 1/2% of subscriptions, without recourse to the partnership.
Included in the "Amount available for investment" line item is the cost to
the
partnerships of acquiring prospects, which may include prospects acquired
from
us.
We will disburse substantially all of the funds available to the
partnership for the following purposes and in the following
manner :
<TABLE>
<C> <C> <C> <C>
<C>
<C> <C> <C>
750 Units 75 Units 1250 Units 125 Units
Sold % Sold % Sold
%
Sold %
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's fee and sales
commission $ 1,575,000 8.6% $ 157,500 8.6% $
2,625,000 8.6% $ 262,500 8.6%
LESS: Management fee to
managing general partner $ 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%
</TABLE>
Subsequent Source of Funds
We will commit or expend substantially all of the partnership's
initial capital following the offering. The limited 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 limited partnership 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 investor
partners
and us, as follows:
Managing
Investor
Partners General Partner
Throughout term of
Partnership 80% 20%
The allocations and distributions to the investor partners and to us
may
vary during the ten years of 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 we must increase our
capital
contribution above our required cash investment of 21 3/4% of subscriptions
to
cover tangible drilling and lease costs, our share of profits and losses and
cash
available for distribution will increase to equal our percentage investment,
and
the investor partners' share will correspondingly decrease. See "Costs -
Lease
Costs, Tangible Well Costs, and Gathering Line Costs," below .
Revision to Sharing Arrangements. The limited partnership agreement
provides for the allocation of partnership profits and losses 80% to
the
investor partners and 20% to us throughout the term of each
limited 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 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 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. To the extent that the sharing
arrangements change in any particular year, the allocations of revenues to
the
investor partners will increase accordingly and the allocation of
revenues to the Managing General Partner will correspondingly decrease. The
above-referenced revised sharing arrangement policy is not, and no investor
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 us as set forth in 4.02 of the limited
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
the policy, will achieve a 12.8% 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.
Revenues
Natural Gas Revenues; Sales Proceeds. The limited 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 us. The production revenues to be
allocated
are subject to "Revision to Sharing Arrangements," immediately above, and
to
revisions due to increases in our capital contributions to cover tangible
drilling and lease costs.
Interest Income. We 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 . We 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 us.
Sale of Equipment. We will allocate to us 100% of all revenues from
sales
of equipment.
Sale of Productive Properties. In the event of the sale or other
disposition of a productive well, a lease upon which well is
situated,
or any equipment related to lease or well, we will allocate and
credit
to the partners the gain from 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. We will allocate these revenues to the investor partners and
us in
the same percentages as allocation of oil and gas revenues.
Costs
Organization and Offering Costs. We, and not the partnership ,
will
pay organization and offering costs, net of the commissions,
discounts
and due diligence expenses, and wholesaling fees, of the
partnerships .
We 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 commissions, discounts, and
due
diligence reimbursement and will be allocated 100% of these costs. However,
we
will allocate and charge to us 100% of organization and offering costs in
excess
of 10 1/2% of subscriptions.
Management Fee. We will allocate the nonrecurring management fee 100%
to
the investor partners
Lease Costs, Tangible Well Costs, and Gathering Line Costs. We will
allocate the costs of leases, tangible well costs and gathering line costs
0% to
the investor partners and 100% to us.
We will contribute and/or pay for the partnership's share of
all
leases, tangible drilling and completion costs, and gathering line costs.
If
these costs exceed our required 21 3/4% capital contribution, we will
increase our capital contribution. In that event, our share of all items
of
profit and loss during the production phase of operations and cash available
for
distribution would be modified to equal for us the percentage arrived at by
dividing our capital contributions by the capital available for investment;
the
investor partners' allocations of these items would be
changed
accordingly.
Intangible Drilling Costs. Intangible drilling costs are costs
required
to drill a well and prepare the well for production. These costs have no
salvage
value. Items like the cost of drilling the well, the cost of grading the
surface
and geological costs associated with selecting a well site are intangible
well
costs. The cost of production equipment, casing pipe, and other equipment
are
tangible costs because it may be possible to remove them from a depleted or
unsuccessful well and sell them or use them somewhere else. We will
allocate
intangible drilling costs and recapture of intangible drilling costs in
proportion to the investor partners' and our 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. Recapture
means
that you must include the income you receive for the sale of partnership
interest
as part of your regular taxable income to the extent the sales price exceeds
your
partnership tax basis, rather than as long-term capital gains. Regular
income
is generally taxed at a higher rate than long-term capital gains.
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, we will
pay
the additional amount of these costs, and in these
circumstances
the sharing arrangements for intangible drilling costs and recapture of
intangible drilling costs will be in proportion to the investor partners'
and our respective payment of intangible drilling costs.
Operating Costs. Operating costs are the costs at the well level
associated with producing and maintaining productive wells, equipment, and
maintaining access roads. We will allocate and charge operating costs
of
partnership wells 80% to the investor partners and 20% to us,
subject to revision in the event of the preferred return and/or our
increased
investment, as we have discussed in this section.
Direct Costs. Direct costs are partnership level costs, primarily
independent auditor and reserve engineer fees and tax preparation. We will
allocate and charge direct costs of the partnerships 80% to the
investor partners and 20% to us, subject to revision in the event
of the
preferred return and/or our increased investment, as we have discussed in
this
section.
Administrative Costs. We will allocate 100% of the administrative
costs
of the partnerships to us.
The table below summarizes the participation of the investor
partners
and us, taking account of our capital contribution, in the costs and
revenues of the partnerships . See "Glossary of Terms,"
"Participation in
Costs and Revenues," and the limited partnership agreement, Exhibit A to
this
prospectus.
With regard to the table below, we, 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, we, without recourse to the partnerships, will pay organization
and
offering costs in excess of 10 1/2% of subscriptions. The "Direct Costs"
line
item represents operating costs incurred after the completion of productive
wells, including monthly per-well charges paid to us. We will receive
monthly
reimbursement from the partnerships for their direct costs incurred by us
on
behalf of the partnerships.
<TABLE>
<C> <C> <C>
Managing
Investor General
Partners Partner
Partnership Costs
Broker-dealer Commissions and Expenses 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 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%
</TABLE>
We estimate 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>
<C> <C> <C>
Minimum Maximum
Subscriptions Subscriptions
(75 Units) (7,500 Units)
Administrative Costs $ -0- $ -0-
Total Administrative Costs
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
</TABLE>
We will bear all administrative costs of the partnerships; however,
the
financial statements of the partnerships will reflect these costs, since
generally accepted accounting principles require that all costs of doing
business
be included in the historical financial statements.
The following table presents for each partnership formed by us 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 .
<TABLE>
<C> <C> <C> <C> <C>
<C>
<C>
Direct Costs
1998 1999 2000
% of % of % of
Partnership Name Amount Subscriptions Amount Subscriptions
Amount Subscriptions
PDC 1998-A 11,304 0.21% 9,287 0.18% 0 0.0%
PDC 1998-B 14,921 0.21% 8,817 0.12% 0 0.0%
PDC 1998-C 14,990 0.19% 9,518 0.12% 0 0.0%
PDC 1998-D 17,780 0.09% 23,261 0.11% 0 0.0%
PDC 1999-A - - 12,351 0.26% 0 0.0%
PDC 1999-B - - 12,995 0.23% 0 0.0%
PDC 1999-C - - 9,617 0.14% 0 0.0%
PDC 1999-D - - 15,123 0.08% 0 0.0%
PDC 2000-A - - - - 0 0.0%
PDC 2000-B - - - - 0 0.0%
PDC 2000-C - - - - 0 0.0%
PDC 2000-D - - - - 0 0.0%
Administrative Costs
1998 1999 2000
% of % of % of
Partnership Name Amount Subscriptions Amount Subscriptions
Amount Subscriptions
PDC 1998-A 0 0.00% 0 0.00% 0 0.00%
PDC 1998-B 0 0.00% 0 0.00% 0 0.00%
PDC 1998-C 0 0.00% 0 0.00% 0 0.00%
PDC 1998-D 0 0.00% 0 0.00% 0 0.00%
PDC 1999-A - - 0 0.00% 0 0.00%
PDC 1999-B - - 0 0.00% 0 0.00%
PDC 1999-C - - 0 0.00% 0 0.00%
PDC 1999-D - - 0 0.00% 0 0.00%
PDC 2000-A - - - - 0 0.00%
PDC 2000-B - - - - 0 0.00%
PDC 2000-C - - - - 0 0.00%
PDC 2000-D - - - - 0 0.00%
</TABLE>
Allocations Among Investor Partners; Deficit Capital Account Balances
We will allocate revenues and costs of a partnership allocated
to
the investor partners among them in proportion to 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 allocations of losses to an investor partner to the
extent allocation would create or increase a deficit in his or her
capital account (adjusted for liabilities, as provided in the
limited
partnership agreement).
Cash Distribution Policy
- Distributions of partnership cash are planned to be made on a
monthly basis, but will be made no less often than quarterly, to the
extent there are funds available for distribution.
- We 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.
- We cannot presently predict amounts of cash distributions from the
.
We intend to distribute substantially all of each partnership's
available cash flow on a monthly basis; however, we will review the accounts
of
each partnership at least quarterly for the purpose of determining
the
distributable cash available for distribution. to make or sustain
cash
distributions will depend upon numerous factors. We can give no assurance
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 us, 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
these
prospects.
In general, we will divide cash distributions 80% to the investor
partners and 20% to us throughout the term of the partnership .
However, we 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.
Our revised sharing arrangement policy is not, and no investor should
consider
the policy to be, any form of guarantee or assurance of a rate of return on
an
investment in the partnership . Cash will be distributed to the
investor partners and us 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
would
create or increase a deficit in that partner's capital account.
For a fuller discussion of capital accounts and tax allocations, see
"Tax
Considerations - Partnership Allocations."
Termination
termination and final liquidation of a partnership , we
will
distribute the assets of the partnership to the partners based
upon
their capital account balances. If we have a deficit in our capital
account, we
must restore 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 limited partnership
agreement
without investor approval, if necessary for partnership allocations to be
recognized for federal tax purposes.
We are authorized to amend the limited partnership agreement, if, in
our
sole discretion based on advice from our legal counsel or accountants, an
amendment to revise the cost and revenue allocations is required for
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 . See Section 11.09 of the limited 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>
<C> <C>
Recipient Form of Compensation Amount
Managing General Partnership interest 20% interest
Partner
Managing General Management fee 2.5% of subscriptions
Partner (nonrecurring fee)
Managing General Sale of leases to Partnerships fair market
value
Managing General Contract drilling rates Partner
Managing General Operator's per-well charges Partner
Managing General Direct costs Cost
Partner
Managing General Payment for equipment, Competitive prices
Partner and supplies, gas marketing and
Affiliates other services
Affiliate Brokerage sales commissions; 10.5% of subscriptions -
reimbursement of due $157,500 ranging to
diligence and marketing $15.75 million
support expenses; wholesaling
fees
</TABLE>
For a tabular presentation of payments to us made by previous
partnerships
sponsored by us, 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 us 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 us.
Following closing of a partnership and upon funding of that
partnership , we will contribute to the partnership an amount
in
cash equal to 21 3/4% of the subscriptions of that partnership's
investors. In exchange for our investment, we will receive a 20% interest
in the
partnership . Our interest in the partnership may vary in view
of
the revised sharing arrangement policy (see in Costs and Revenues
-
Profits and Losses; Cash Distributions - Revision to Sharing Arrangements
and if we invest additional capital to fund that partnership's
tangible drilling and lease costs (see in Costs and Revenues - Costs
-
Lease Costs, Tangible Well Costs, and Gathering Line .
Upon completion of the offering with respect to each
partnership and
upon funding of that partnership , we 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 we can sell a maximum of $15 million ($25 million with
respect to each of PDC 2001-D Limited Partnership, PDC 2002-D Limited
Partnership, and PDC 2003-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 each of to PDC 2001-D Limited Partnership, PDC 2002-D Limited
Partnership, and PDC 2003-D Limited Partnership).
The partnership will reimburse us for all documented
out-of-pocket
expenses incurred on behalf of the partnership ; however, there will
be no
reimbursement of administrative costs by a partnership .
We will sell (at the lower of fair market value on the date of
purchase or
our cost of prospects) sufficient undeveloped prospects to the
partnership to drill the partnership's wells. Fair market
value
for leases and prospects transferred from our 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 our reasonable, necessary
and
actual expenses for geological, geophysical, engineering, interest expense,
drafting, legal, and other like services allocated to the
partnership's
properties. We will not retain any overriding royalty for ourselves from
prospects (see "Proposed Activities - Acquisition of Prospects"
will enter into a drilling contract with us 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 us may
drill,
complete, and operate wells on prospect. We may use our own
personnel
and equipment during the drilling and completion phase of operations. We
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 our actual costs of drilling and completion, we will be deemed to
have
received compensation. The amount of compensation which we 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. We estimate that we would
need
to drill approximately 50-70 wells annually to absorb fully existing
technical,
supervisory, and management costs.
The partnership will pay us, 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. See "Proposed Activities
-
Drilling and Completion Phase - Drilling and Operating Agreement." 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
these rates exceed competitive rates available from other persons in the
area
engaged in the business of providing comparable services or equipment, we
will
adjust the foregoing rates to an amount equal to that competitive rate, but
not
less than the cost of providing services or equipment. In the
event
that the competitive industry rates in the area and our costs in providing
these
drilling and completion services are in excess of our contract drilling and
completion rates, we will be bound by contract with the partnership
to
furnish the contracted services at the contract rates. We review 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. We will determine
comparable rates from one of the following sources: offering memoranda or
prospectuses for private or public drilling programs, quoted rates,
published
rates or costs, or competitive bids. In utilizing outside contractors for
drilling and completion operations (rather than performing these services
ourselves), we 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 1999
-
2000 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;$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; and
$5,088
per well per month for wells in Wyoming. 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 we
determine
to conduct our drilling activities in other geographical areas or to other
geologic zones, we 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 costs.
See
"Proposed Activities - Drilling and Completion Phase - Drilling and
Operating
Agreement
will reimburse us for direct costs incurred by us on behalf of
the
partnerships .
We and our 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. We intend to market some of the gas produced through our
subsidiary
Riley Natural Gas. See "Conflicts of Interest
PDC Securities Incorporated, our affiliate, 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
may,
as dealer manager, reallow 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 natural gas from development wells.
- We may conduct limited exploratory activities.
- 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 Colorado, Michigan, West
Virginia, Pennsylvania, Utah, and Wyoming as described in this prospectus.
We
may also conduct partnership operations in other formations not
described
in the prospectus, in the previously listed states, or in Montana, New York,
South Dakota, Kentucky, Tennessee, Indiana, Kansas, North Dakota, Nebraska,
Ohio
and/or Oklahoma as we may deem advisable. We intend to apply at least 90%
of
each partnership's 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. We will spread the risks to a limited extent by having each
partnership participate in drilling operations on a number of
different
prospects. The cost of drilling wells in different geographic locations
will
vary greatly. If we drill 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 that partnership and the specific prospects
drilled
by that partnership , and cannot be determined in advance of funding
of a
partnership .
The provides you with an opportunity to invest in the
drilling,
completion, and production of natural gas wells. of the investment
in the program .
You 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 our ability to select productive prospects, the
drilling and completion of wells in an economical manner, the successful
management of 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, we can give no assurance
that
the partnership will achieve its business objectives. Moreover,
because
each partnership will constitute a separate and distinct business and
economic entity from each other Partnership, the degree to which the
business
objectives are achieved will vary among the partnerships .
Various of the activities and policies of the partnership
discussed
throughout this section and elsewhere in the prospectus are defined in and
governed by the limited partnership agreement, 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 our capital contribution to the partnership ; the guidelines with
respect to well pricing and the cost of services furnished by us; the states
where the partnership's wells will be drilled; assessments and
borrowing
policies; voting rights of investor partners ; the term of the
partnership ; and our compensation. Other policies and restrictions
upon
the activities of the partnership and us are not set forth in the
limited
partnership agreement, but instead reflect our current intention and thus
are
subject to change at our discretion. For these later activities, we, in
making
a change, will utilize our reasonable business judgment as manager of the
partnership and will exercise our judgment consistent with our
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) We will assign to the partnership up to 100% of the
working interest in the prospects; and
(b) The partnership will enter into a drilling and
operating
agreement with us or with unaffiliated persons as operator, providing
- for the drilling and completion of
partnership wells and
- 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 adjacent producing wells and drilled to the same formation(s) as the
producing wells. . 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 us, or if there is reliable evidence that
there would be material drainage of a partnership prospect by an
adjoining
spacing unit in which we own an interest, we will assign to the
partnership a proportionate interest in spacing unit.
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.
We will select undeveloped prospects sufficient to drill the
partnerships' wells. We have not pre-selected any prospects. Most
prospects to be selected for the partnerships are expected to be
single
well proved undeveloped prospects. We define a prospect generally as a
contiguous oil and gas leasehold estate, or lesser interest , 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 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 Colorado, Utah and Wyoming to develop Cretaceous Sandstones. We reserve
the
right to conduct partnership operations in New York, Ohio, Montana,
South
Dakota, Tennessee, Kentucky, Indiana, Kansas, North Dakota, Nebraska and/or
Oklahoma and/or to other formations as we may, in our sole and
absolute
discretion, deem advisable, provided that locations and/or
formations
are, in our opinion, of comparable quality and character to those described
in
this prospectus.
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. We anticipate that
gas
will be produced from all the subject wells. There could also be some oil
and
brine production. will acquire prospects under arrangements
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 royalty interests for all prospects of a particular
partnership will not exceed 20%. In our discretion, we may acquire
less
than 100% of the working interest in a prospect provided that costs are
reduced
proportionately. The limited partnership agreement forbids us 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 conditions for the treatment of additional general
partners' interests in the partnership as not passive activities
(and
not subjecting the additional general partners to limitation
on
the deduction of partnership losses attributable to to income
from
passive activities), we have 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. We, for
our
sole benefit, may sell or otherwise dispose of prospect interests not
acquired
by the partnerships or may retain a working interest in
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
consideration and make contractual commitments and agreements as we
deem
fair, reasonable and appropriate. While we expect to assign to the
partnerships a substantial portion of the leases to be developed by
the
partnerships may also purchase leases directly from unaffiliated
persons.
We will transfer at our cost all leases which are transferred to the
partnerships , unless we have reason to believe that cost is
materially
more than the fair market value of property in which case the price
will
not exceed the fair market value of property. We will obtain an
appraisal from a qualified independent expert with respect to sales of our
properties 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 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.
We will assign the partnership interest in the lease to the
partnership . Leases acquired by each partnership may
initially and
temporarily be held in our name, as nominee, to facilitate joint-owner
operations
and the acquisition of properties. The existence of the unrecorded
assignments
from the record owner will indicate that the leases are being held for the
benefit of each particular partnership and that the leases are not
subject
to debts, obligations or liabilities of the record owner; however,
unrecorded assignments may not fully protect the partnerships from
the
claims of our creditors.
You must rely on us to use our best judgment to obtain appropriate
title
to leases. Provisions of the limited partnership agreement relieve us from
any
mistakes of judgment with respect to the waiver of title defects. We will
take
steps as we deem necessary to assure that title to leases is
acceptable
for purposes of the partnerships . We are free, however, to use our
own
judgment in waiving title requirements and will not be liable for any
failure of
title to leases transferred to the partnerships . Further, we will
not
warrant the validity or merchantability of titles to any leases to be
acquired
by the partnerships .
PDC Prospects
We anticipate that our four geologists (see "Management - Petroleum
Development Corporation" will evaluate all prospects, utilizing log
and
geological data from our historic operations, production records from our
and
others' wells, and other information as may be available and useful.
wells. As a result, nearly all wells drilled by the partnership
will
be direct offsets to existing producing wells. 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 September 30, 2000, we had acreage available as listed in the
following table within the prospect area.
County Acreage
West Virginia 14,000
Pennsylvania 19,200
Michigan 21,900
Utah 58,800
Colorado 14,200
Total 128,100
In addition, we expect to acquire additional acreage on an ongoing
basis
throughout 2001 and beyond for the and future partnerships.
We will not decide on the specific wells to be drilled in any
partnership until the offering of units in that partnership
has
terminated. This means that you will not be able to evaluate the specific
prospects that will be drilled by your partnership . However, by
waiting
as long as possible before selecting the specific prospects to be drilled
by the
partnership , we may have information available which helps us select
better prospects for the partnership , and we may be able to include
prospects which were not available when this prospectus was written or even
before the partnership was closed. This section includes a general
description of the characteristics we look for in prospects to be included
in the
as well as more detailed information on several areas where we
anticipate
partnership wells may be drilled. We will provide supplemental
information if and when we add additional prospect areas.
In selecting areas where we plan to drill partnership wells,
we look
for areas with most or all of the following general characteristics:
- Natural gas expected to be the primary product
- Onshore wells with depths of 10,000 feet or less
- Expected average producing lives of 20 years or more
- Existing pipeline systems which allow quick
connection
for sales
- Adequate market capacity for increased gas
production
- Low dry hole risk
Most of the wells drilled by the partnerships will be targeted
at
natural gas producing intervals. These intervals may also contain oil and/or
water which are produced in conjunction with the natural gas. Some natural
gas
also contains hydrocarbons like propane and butane which may be separated
from
the natural gas and sold. Water that is produced must be disposed of by an
environmentally approved method, which adds to the cost of operating the
wells.
Over the past 30 years, we have drilled more than 2000 wells at depths
ranging to just over 10,000 feet. When we select new prospect areas, we
look for
places where the drilling conditions are similar to areas where we have had
drilling experience and where the well depths do not exceed approximately
10,000
feet. Because we have had no offshore experience, we do not plan to include
any
offshore prospects in the .
Since we started organizing partnerships in 1984, we have completed
more
than 90 percent of the wells we have drilled for our partnerships to produce
natural gas. Our completion record reflects our selection of prospect areas
where the probability of drilling dry holes is relatively low because
producing
intervals exist throughout a large area and because each well may access
several
intervals which are capable of producing natural gas or oil. Nevertheless,
high
completion rates do not guarantee economic success if the wells do not
produce
sufficient quantities of natural gas and oil or if the prices for natural
gas and
oil are at low levels. All of the areas we are currently developing fit
this
general description and we plan to look for similar characteristics in
prospect
areas we might add in the future. We also look for areas where the
characteristics of the producing formations lead to relatively long
producing
lives, generally of 20 years or more. Production from wells typically
commences
at a maximum rate that diminishes over the life of the well. This means
that the
income stream from the wells will also tend to decline over time, depending
upon
other factors including the sales price for the production and operating
expenses.
As we evaluate the geology of a prospect area, we also determine
whether
there is an adequate market for natural gas and oil which may be produced
by the
wells. For natural gas, this includes the existence of pipelines to move
the gas
from the wells to natural gas markets. We look at the proximity of existing
pipelines to planned drilling, the cost of moving gas to market, and prices
being
paid for gas in the markets which are available. Similarly, there must be
both
a market and suitable transportation for oil production.
Current Prospect Areas
Colorado. Wattenberg Field, located north and east of Denver, Colorado, is
in the Denver-Julesburg (DJ) basin. The field, discovered in 1970,
has
produced over 600 billion cubic feet of natural gas and 2.2 million barrels
of
oil. The typical well production profile has an initial high production
rate and
relatively rapid decline, followed by years of relatively shallow decline.
Natural gas is the primary hydrocarbon; however, many wells will also
produce oil. The purchase price for the gas may include revenue from the
recovery of propane and butane in the gas stream, as well as a premium for
the
high-energy content of the gas.
Wells in the area may include as many as four productive formations.
From
shallowest to deepest, these are the Sussex, the Niobrara, the Codell and
the J
Sand. The primary producing sand in most wells will be the Codell; this
sand
produces a combination of natural gas and oil.
The Piceance Basin, located near the western border of Colorado, is
a
second Colorado prospect area. We expect our Piceance Basin wells to
produce
natural gas along with very small quantities of oil and water. The
producing
interval
Michigan. The Antrim shale of the Michigan Basin was one of the most active
shallow gas development plays in the U.S. during the 1990s. The producing
formation in most partnership wells is expected to be approximately
800
to 1,500 feet below the surface.
The Antrim shale is initially water-charged. For us to produce
natural
gas, we must remove this water from the producing formation. Antrim shale
wells
are drilled in projects of 10 to 20 wells that are operated as a unit and
share
common compression, water separation, and water disposal facilities.
West Virginia and Pennsylvania (Appalachian Basin). The Appalachian Basin
is one
of the oldest producing areas in the country. As a result, it has a
well-developed pipeline gathering system for natural gas. Over 90 percent
of the
economic value of Appalachian Basin production is generated from the sale
of
natural gas, with occasional small quantities of oil.
Prospects that we might include in the are less than 6,000
feet
in depth. In most areas there are several potentially productive formations
stacked one atop another. This multiple pay potential has historically
resulted
in high completion rates for wells drilled in the area.
Utah. The Uinta Basin in northeastern Utah contains more than 100 oil and
natural gas fields which have collectively produced over 1.3 trillion cubic
feet
of natural gas and over 100 million barrels of oil. This production is from
four
different plays: the Tertiary Uinta, Green River and Wasatch formations, and
the
Cretaceous Mesaverde formation. Wells may contain several pay zones.
Similar
to Colorado, the primary hydrocarbon produced is natural gas with some
associated
oil and water.
Southwest of the Uinta Basin in central Utah, about a two-hour drive
from
Salt Lake City, is the Wasatch Plateau. The Cretaceous-aged Ferron
Formation
produces natural gas from both sandstone and coal reserves. Cumulative
production from this play since the discovery well in 1951 exceeds 120 BCF
of
natural gas.
Wyoming. Our drilling target in the Green River Basin in southwestern
Wyoming
and northwestern Colorado will be Cretaceous-aged reservoirs.
Cumulative
production from just two plays, the Mesaverde and the Lewis Shale, is over
2.2
trillion cubic feet of natural gas.
Similar to many of the Rocky Mountain producing areas, the majority
of
drilling efforts in the last decade in the Green River Basin have focused
on
low-permeability reservoirs which have become economic through improvements
in
drilling and completion technology. The typical production profile for
these
reservoirs has a majority of reserves produced within the first few years
of
production life followed by many years of relatively stable, shallow
decline.
Summary of Prospect Areas
The following table summarizes some of the key characteristics of our
current prospect areas:
<TABLE>
<C> <C> <C> <C> <C> <C>
Prospect
Productive
Formation
Depth
Range
Type of
Reservoir
Rock
Thickness of
Producing
Interval
Anticipated
Production
Wattenberg Field,
Colorado
Sussex
3,750'- 5,250'
Sandstone
10'-60'
Natural gas
Niobrara
6,500'- 7,500'
Limestone
20'- 80'
Natural gas
Codell
6,750'- 7,750'
Sandstone
10'-30'
Natural gas, oil
J Sandstone
7,500'- 8,400'
Sandstone
2'-90'
Natural gas
Piceance Basin,
Colorado
Williams
Fork
6,000'- 10,000'
Sandstone and Coal
150'-300' total pay in a 2,000- 4,000 interval
Natural gas
Michigan
Antrim Shale
500'- 2,500'
Fractured shale
100' in two zones
Natural gas
West Central and Southern Pennsylvania
Upper Devonian Formations
3,000'- 5,000'
Several Sandstone Zones
5'-25' per zone with total pay of 40'- 100' per well
Natural gas
Northern
West Virginia
Mississippian
Formations
2,000'- 3,000'
Several Sandstone
Zones
5'- 50'
Natural gas
Upper Devonian Formations
2,500- 6,000'
Several Sandstone Zones
4'- 30'
Natural gas
Southern West Virginia
Mississippian Formations
2,000'- 4,000'
Sandstone, Limestone
Individual zones 5'-50', may be several zones in a single well
Natural gas
Uinta Basin,
Utah
Uinta
2000' - 5000'
Sandstone
15' - 50'
over
1000' - 5000'
interval
Natural gas
Green River
2300' - 7500'
Sandstone & Limestone
100' - 300'
over
2000' to 6000'
interval
Natural gas, Oil
Wasatch
3000' - 10,700'
Sandstone
100' - 200'
over
1500' - 3000'
interval
Natural gas
Mesaverde
4200' - 13,500'
Sandstone
20' - 100'
over
1200' - 2700'
interval
Natural gas
Wasatch,
Utah
Ferron
5500' - 7800'
Sandstone
and Coral
10' - 30'
Natural gas
Green River Basin,
Wyoming
Mesaverde
2000' - 14,000'
Sandstone
10' - 100'
Natural gas
Lewis
3100' - 10,000'
Sandstone
10' - 30'
Natural gas
</TABLE>
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 to 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.
- Partnership wells in Utah and Wyoming may be exploratory or
developmental
with depths expected to range from 5,000 to 14,000 feet in depth.
- The Managing 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 table above shows the anticipated depths and target formations
for
planned areas of operations.
We may drill some shallower or deeper development prospects in these areas.
If
we drill 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. We 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, we will utilize these funds together
with
unexpended completion funds to drill additional development wells.
We may substitute another operator or operators to perform the duties
of
the operator, on terms and conditions substantially the same as those
discussed
in this prospectus. 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 prospects will select the operator for the
wells
drilled on prospects and that the operator may not be us. In the
event
another company acts as operator, we 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 us serves as operator, the cost of
drilling
to the partnership will be the actual cost of third-party drilling,
plus
our 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.
We 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 we
are
the operator. We expect to be the operator of most if not all of the wells
in
which the partnerships own an interest.
We will, in some cases, provide equipment and supplies, and will
perform
salt water disposal services and other services for the partnerships ,
provided that all these transactions will be at competitive prices
and
upon competitive terms. We may sell equipment to the partnerships
as
needed in the drilling or completion of partnership wells. All
equipment will be sold at prices competitive in the area of operations.
Gas Pipeline and Transmission: We will drill the partnership's
wells
in the vicinity of transmission pipelines, gathering systems, and/or end
users.
We believe 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. We intend to utilize the services of our subsidiary in
marketing the gas produced from partnership wells. We 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, 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.
- The operator must commence drilling wells within 180 days after
funding of
the partnership , but not later than March 31, 2002 for
partnerships
designated "PDC 2001- Limited Partnership," March 31, 2003 for
partnerships designated "PDC 2002- Limited Partnership" and March 31,
2004
for partnerships designated as "PDC 2003-Limited Partnership."
- The costs charged for drilling and completion, dry holes, and
monthly
operations will be competitive with rates charged for similar services
and
will vary by 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 a drilling and operating agreement with us as
operator.
The (filed as Exhibit 10(a) to the 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 , we may subcontract responsibilities as operator for
partnership wells. We will retain responsibility for work performed
by
subcontractors as set forth in this prospectus.
It is possible that we will not be operator on some of the
partnership's 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 our 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 our
discretion, 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 joint venture is
proportional to
its contribution to the total cost of venture.
It is anticipated that the partnerships , PDC, and other third
party
joint venturers will share the cost of the Michigan Antrim projects. The
limited
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 to the
other
joint venture partners through the use of a tax partnership. In return for
contribution of the wells costs to an Antrim project, the
partnerships
will acquire a 55% working interest in the project. The remaining working
interests will be allocated to the parties bearing the project costs for
multiple
flowlines, leases, salt water injection well, and equipment for the central
production facility. Michigan Antrim project leases are unitized for the
purpose
of payment of royalties, distribution of working interest revenue and
allocation
of project production expenses.
Project working interest revenue and project production expenses are
allocated to working interest owners based on the number of net wells
drilled,
completed and placed into production, expressed as a percentage of the total
number of wells then producing in a project proportional to their ownership
interest. To the extent that a partnership drills and pays for less
than
the total number of wells in a project, its overall working interest in the
project will be proportionately reduced.
Each partnership will be responsible only for its obligations
and
will be liable only for its proportionate share of the costs of developing
and
operating the prospects; and, in the event of the default of another party,
we
have agreed to indemnify the partnership and its partners for
the
obligations of party. If any party fails or is unable to pay its
share
of expense within 60 days after rendering a statement therefore by us, we
will
pay the unpaid amount in the proportion that the interest of each
party
bears to the interest of all 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 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, 2002 for partnerships designated "PDC
2001-Limited Partnership," March 31, 2003 for partnerships designated
"PDC
2002-Limited Partnership," and March 31, 2004 for partnerships
designated
"PDC 2003- Limited Partnership." The operator's duties include testing
formations during drilling, and completing the wells by installing
surface and well equipment, gathering pipelines, heaters, separators, etc.,
as
are necessary and normal in the area in which the prospect is located. We
will
pay the drilling and completion costs of the operator as incurred, except
that
we are 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 will not refund
any
portion of amounts paid in the event actual costs are less than amounts paid
but
will apply any 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 wells, where we serve as
operator as follows:
1) The cost of the prospect; 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 costs for directional drilling
services,
if required; or
(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 costs for work required by state law in the
event
an intermediate or third string of surface casing is run, plus the actual
costs
for directional drilling services, if required; and
3) The tangible costs of drilling and completing the
partnership
wells and of gathering pipelines necessary to connect the well to the
nearest
appropriate sales point or delivery point.
To the extent that a partnership acquires less than 100% of a
prospect,
its drilling and completion costs of that prospect will proportionately
decrease.
The depth used for determining well charges will be the deepest penetration
by
the drilling bit.
<TABLE>
<C> <C> <C> <C> <C>
FOOTAGE BASED RATES
LOCATION
TARGET FORMATIONS
APPROXIMATE WELL DEPTH
INTANGIBLE DRILLING AND COMPLETION COSTS
INTANGIBLE DRY HOLE COST
Northern West Virginia and Pennsylvania
Upper Devonian and Mississippian
2,000 - 5,000'
$60 per foot for first 2,200 feet plus $16 per foot for each additional foot
below 2,200 feet
$33 per foot for the first 2,200 feet plus $9 per foot for each additional
foot
below 2,200 feet
Michigan
Devonian
Antrim Shale
Richfield
800 - 4,500'
$138 per foot for the first 1,000 feet plus $22 per foot for each additional
foot
below 1,000 feet
$60 per foot for the first 1,000 feet plus $12 for each additional foot
below
1,000 feet
Wattenberg Field Colorado
Cretaceous Codell
6,500 - 7,800'
$55 per foot
$18 per foot
Wattenberg Field Colorado
Cretaceous J Sandstone
7,000 - 8,000'
$67 per foot
$21 per foot
Piceance Basin Colorado
Cretaceous Mesaverde
7,000 - 10,000'
$130 per foot
$75 per foot
Utah
Uinta
Green River
Wasatch
Mesaverde
Ferron
5,000 - 14,000'
$130 per foot
$75 per foot
Wyoming
Mesaverde
Lewis
Almond
7,000 - 14,000'
$130 per foot
$75 per foot
</TABLE>
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, we will adjust the foregoing
rates
to an amount equal to that competitive rate.
The provides that the partnership will pay the
operator the
prospect cost and the dry hole cost for each planned well prior to the spud
date,
and the balance of the completed well costs when the well is completed and
ready
for production, in the case of a completed well.
The operator will provide all necessary labor, vehicles, supervision,
management, accounting, and overhead services for normal production
operations,
and will deduct from partnership revenues a monthly charge 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 are shown below. 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.
<TABLE>
<C> <C> <C>
INITIAL PER WELL OPERATING CHARGES
WELL LOCATION
MONTHLY PARTNERSHIP ADMINISTRATION
MONTHLY WELLTENDING FEE
Appalachian Basin
$75
$225
Michigan Basin
$75
$225
Colorado
$75
$600
Utah
$75
$600
Wyoming
$75
$600
</TABLE>
The partnership will have the right to take in kind and
separately
dispose of its share of all oil and gas produced from its prospects,
excluding
its proportionate share of production required for lease operations and
production unavoidably lost. Initially the partnership will
designate the
operator as its agent to market production and authorize the
operator
to enter into and bind the partnership in agreements as it
deems
in the best interest of the partnership for the sale of oil
and/or gas. If pipelines which have been built by us 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, 2004 to an amount equal to the rates initially established by the
, 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 will continue in force so long as any 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 the price of gas sold will vary as
a
result of market forces.
- The partnership may enter into fixed price
contracts or use financial hedges to fix gas prices, which may result in
greater
or lower prices than market sensitive prices.
- The partnership will not complete contracts
for
sale of gas until after 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. The partnership will not complete contracts for sale of
gas
until after drilling of the wells, except as noted below.
The partnership will sell the produced gas to industrial users,
gas
marketers, including affiliated marketers, commercial end users, interstate
or
intrastate pipelines or local utilities, primarily under market sensitive
contracts the price of gas sold will vary as a result of market
forces.
Some leases, and thus the gas derived from wells drilled on those leases,
may be
dedicated to markets at the time we acquire those leases.
The partnership may enter into fixed price contracts, or
utilize
derivatives, including hedges, swaps or options in order to achieve price
certainty for periods of time, generally for less than one year.
The use
of derivatives may entail fees, including the time value of money for margin
requirements, which will be charged to the partnership .
We may utilize our subsidiary to market gas, enter into
hedges or
swaps, or purchase options on behalf of the partnership will be
entitled
to charge reasonable fees for its services, including out-of-pocket costs.
These
fees, however, will be equal to or less than fees charged to non-affiliated
producers for similar services.
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, taxes 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 our practice 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
We, 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
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.
Landowner and other royalty interests payable to unaffiliated third parties
may
vary, provided that the weighted average of royalty interests for
all
prospects of a partnership shall not exceed 20%. The revenues to be
distributed
are subject to the revised sharing arrangement policy and to revisions if
we make
a capital contribution greater than our 21 3/4% requirement.
Program Revenue Sharing
Partnership Working Interest Third Party Royalties:
Entity Interest If 12.5% /If 20%
Managing 20% Partnership
General Interest
17.50% 16.00%
Partner
Investor 80% Partnership
Partners Interest
70.00% 64.00%
Third Landowners and Over-
Parties riding Royalties 12.50% 20.00%
100.00% 100.00%
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.
We, in our capacity as operator, will carry blowout, pollution, public
liability and workmen's compensation insurance, but insurance may
not
be sufficient to cover all liabilities. Each unit held by the
additional general partner 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.
We have obtained various insurance policies, as described below, and
intend
to maintain these policies subject to our analysis of their premium
costs,
coverage and other factors. We may, in our sole discretion, increase or
decrease
the policy limits and types of insurance from time to time as we deem
appropriate
under the circumstances, which may vary materially. The following types and
amounts of insurance have been obtained and are expected to be maintained.
We
are the beneficiary under each policy and pay 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.
We, as Managing General Partner and operator, have determined in good
faith, in the exercise of our 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 coverage
as
we believe is sufficient to protect the investor partners against
the
foreseeable risks of drilling. We 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 is in excess of
$25
million in the aggregate, we 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 .
We will maintain two-times insurance coverage during
drilling
activities. We will review the partnership insurance coverage prior
to
commencing drilling operations and periodically evaluate the sufficiency of
insurance. We will obtain and maintain insurance coverage as we
determine to be commensurate with the level of risk involved. In more than
30
years of operations, drilling more than 2,000 wells in Tennessee, Ohio,
Pennsylvania, Michigan, Colorado, Montana and West Virginia, our largest
insurance claim has been less than $80,000.
The annual cost of 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.
We will notify all additional general partners at least 30 days
prior to any material change in the amount of 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 have
the
right to convert their units into units of limited partnership
interest by giving written notice to us 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, we will amend the limited
partnership agreement and will file amendment with the State of
West
Virginia prior to the effective date of the change in insurance coverage and
effectuate the conversion of the interest of the former
additional
general partner to that of a limited partner .
The Managing General Partner's Policy Regarding Roll_Up Transactions
Although we have 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 and the issuance of securities by the in cases where
there
is also a significant adverse change in the voting rights of the investor
partners , the term of existence of the partnership , our
compensation,
or the investment objectives of the partnership . The determination
of
"significant adverse change" will be made solely by us in the exercise of
our
reasonable business judgment as manager of the partnership and
consistent
with our obligations as a fiduciary to the investor partners .
The limited partnership agreement provides various policies in the
event
that a 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 ;
(2) Any participant who votes "no" on the proposal will
be
offered a choice of:
- accepting the securities of the
offered in the proposed or
- 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;
(3) will not participate in a proposed
- which would result in the diminishment
of an
investor partner's voting rights under the chartering
agreement;
- in which the investor partners'
right
of access to the records of the would be less than those provided
by the
limited partnership agreement; or
- in which any of the costs of the
transaction
would be borne by the partnership if the proposed is not
approved
by the investor partners .
The limited partnership agreement further provides that the
partnership will not participate in a transaction unless the
transaction is approved by at least 66 2/3% in interest of the
investor
partners . See Section 5.07(m) of the limited 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 . As a result of this competition and Federal Energy
Regulatory Commission ("FERC") and Congressional deregulation of gas prices,
prices are generally determined by competitive forces.
There will also be competition among operators for drilling equipment,
tubular goods, and drilling crews. competition may affect the
ability
of each partnership to acquire leases suitable for development by the
partnerships and to develop expeditiously leases once they
are
acquired.
The marketing of any oil and gas produced by a 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 U.S. markets. these 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 established an industry-wide
structure for "open-access" transportation service under which pipelines
must
provide third parties non-discriminatory access to transportation service
on
their systems. Order No. 636 has restructured the natural gas industry and
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.
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. these 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 this convergence, 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 according to the United States Energy
Information Administration . Nearly half of the 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, increasing foreign competition for natural gas production.
Legislation that Congress may consider with respect to oil and gas may
increase
or decrease the demand for the Partnerships' production in the future,
depending
on whether 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
price levels. We are 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, Equitrans, Colorado
Interstate Gas, NARCO, Duke and others. These companies have all
traditionally
purchased substantial portions of their supply from West Virginia, Michigan,
Colorado or Pennsylvania producers. In addition, all are subject to
regulations
enacted by state commissions or the FERC which require them to transport gas
for
others. Transportation on these systems requires that gas delivered meet
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 , 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. As a result of FERC regulations that require interstate
gas
pipelines to separate their merchant activities from their transportation
activities and require them to release available capacity on both a short-
and
a long-term basis, must take an increasingly active role in
acquiring
their own gas supplies. Consequently, pipelines and 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 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 communications 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 methods to access and integrate all gas supply and transportation
information on a nationwide basis, via the Internet, 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.
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.
- The partnership may enter into fixed price
contracts or use financial hedges to fix gas prices, which may result in
greater
or lower prices than market sensitive prices.
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 our control. In the past, we have 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 us. 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.
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,
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.
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 ,
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").
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 environmental controls will also
affect partnership operations. these 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
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.
Proposed Regulation
Various legislative proposals in Congress and in state legislatures
could,
if enacted, affect the petroleum and natural gas industries. these
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 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, 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, Ohio, Michigan and the Rocky
Mountains.
As of September 30, 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.
We will actively manage and conduct the business of the
partnerships
devoting time and talents to management as we shall deem
reasonably necessary. We 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. We 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
In addition to managing the affairs of the partnership, the management
and
technical staff of PDC also manage the corporate affairs of the company, the
affairs of 56 partnerships formed prior to the current program, and other
joint
ventures formed over the years. We own an interest in all of the older
partnerships and wells in addition to the interest we will purchase in the
PDC
2003 Drilling Program partnerships. Since we must divide our attention and
efforts among many unrelated parties, your partnership will not receive our
full
attention or efforts at all times.
Experience and Capabilities as Driller/Operator
PDC will act as driller/operator for the wells. Since
1969
has drilled over 2,000 wells in West Virginia, Tennessee, Ohio,
Michigan, Colorado and Pennsylvania. currently operates
approximately
2,250 wells.
employs four geologists who develop prospects for drilling by
and who help oversee the drilling process. In addition, has an
engineering staff of four who are responsible for well completions,
pipelines,
and production operations. 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,
may provide services, at competitive rates, from - owned service
rigs,
a water truck, , roustabouts, and other assorted small equipment.
may lay short gathering lines, or may subcontract all or part of the
work
where it is more cost effective for a partnership. 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 us are provided
at
rates less than or equal to prevailing rates for similar services provided
by
unaffiliated persons in the area.
Petroleum Development Corporation
The executive officers, directors and key technical personnel of PDC,
their
principal occupations for the past five years and additional information are
set
forth below:
<TABLE>
<C> <C> <C> <C>
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 Riley 47 Vice President - April 1996
Gas 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 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 since 1955, . Mr. Morgan is not active in
the
day-to-day business of PDC, but his law firm provides legal services to PDC.
Vincent F. D'Annunzio has served as president of Beverage
Distributors, Inc., located in Clarksburg, West Virginia since 1985 .
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 since 1975 .
Thomas Riley has served as Vice President - Gas Marketing and
Acquisitions
of PDC since April 1996. Prior to joining PDC, Mr. Riley was president of
Riley
Natural Gas Company , a natural gas marketing company, from its
inception
in 1987. PDC acquired in April 1996. Mr. Riley continues to serve
as
president of PDC's wholly-owned subsidiary.
Ersel Morgan was elected Vice President-Production in April 1995. He
joined PDC as a landsman in 1980.
Eric Stearns was elected Vice President-Exploration and Development
in
April 1995. Mr. Stearns joined PDC in 1985 after working as a mudlogger for
Hywell, Incorporated logging wells in the Appalachian Basin between 1982 and
1985, and for Petroleum Consultants, Inc. between 1984 and 1985.
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 BS degree in petroleum engineering from Pennsylvania State
University. Prior to joining PDC, Ms. Foster worked as a petroleum engineer
in
the Appalachian Basin with several 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 in Ohio and an
M.S.
degree in geology from West Virginia University as well as other
post-graduate
studies and seminars. Prior to joining PDC, Mr. Carpenter was employed as
Manager of Exploration and Development of Alamco, Inc. from 1996-1997, and
by
Ashland Exploration, Inc. and Shell Oil Company.
Certain Shareholders of Petroleum Development Corporation
The following table sets forth information as of September 30, 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>
<C> <C> <C>
Amount Percent
Name Beneficially Owned(1) of Class
Fidelity Management 1,573,800 9.9
James N. Ryan (2)(3) 986,320 6.1
Dimensional Fund Advisors 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 D'Annunzio (5) 43,600 *
Jeffrey C. Swoveland (6) 18,094 *
All Directors and Officers
as a Group (6 persons) (7) 2,248,940 13.6
</TABLE>
* Less than 1%
(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 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 persons
can
currently exercise or that will become exercisable within 60 days.
Remuneration
None of our officers or directors will receive any direct remuneration
or
other compensation from the partnerships persons will receive
compensation
solely from PDC. Information as to compensation paid by us to our directors
and
executive officers may be obtained from publicly available reports filed by
us
with the Securities and Exchange Commission the Securities Exchange
Act
of 1934.
Legal Proceedings
We as driller/operator are subject to minor legal proceedings
arising from the normal course of business. these legal actions are
not
considered material to the operations of the partnership or us.
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 provide drilling
and
completion services with respect to partnership wells.
- The Managing General Partner is general partner of
numerous other partnerships, and owes duties of good-faith dealing to
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 us. These conflicts include, but are
not
limited to, the following:
Future Programs by Managing General Partner and Affiliates. We have
the
right and expect 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 our own behalf
or for
other private or public investors. Affiliates of ours also intend to
conduct
activities on their own behalf. Officers, directors and employees of
ours
have participated, and will participate in the future, at cost, in working
interests in wells in which we and our partnerships participate. To the
extent
our affiliates invest in the partnerships or other partnerships
sponsored
by us, conflicts of interest will arise.
Fiduciary Responsibility of the Managing General Partner. We are
accountable to the partnership as a fiduciary and consequently have
a duty
to exercise good faith and to deal fairly with the investors in handling the
affairs of the partnership . While we will endeavor to avoid
conflicts of
interest to the extent possible, conflicts nevertheless may occur
and,
in event, our actions may not be most advantageous to the
partnership and could fall short of the full exercise of
fiduciary duty. In the event we should breach our fiduciary
responsibilities, you would be entitled to an accounting and to recover any
economic losses caused by breach, only after either proving a
breach in
court or reaching a settlement as provided with us.
Independent Representation in Indemnification Proceeding. Counsel to
the
partnership and to us in connection with this offering are the same.
dual representation will continue in the future. However, in the event
of
an indemnification proceeding between the partnership and us, we will
cause the partnership to retain separate and independent counsel to
represent its interest in proceeding.
Due Diligence Review. PDC Securities Incorporated, the of the
offering, is our affiliate and its due diligence examination concerning this
offering cannot be considered to be independent. See "Plan of
Distribution
Managing General Partner's Interest. Although we believe that our
interest
in partnership profits, losses, and cash distributions is equitable
(see
"Participation in Costs and Revenues" , our interest was not
determined
by arm's-length negotiation.
Transactions between the Partnership and Operator. We will also act
as
operator. Accordingly, although we believe the terms of the drilling and
operating agreement will be equitable, it will not be the subject of
arm's-length
negotiation. Furthermore, we may be confronted with a continuing conflict
of
interest with respect to the exercise and enforcement of the rights of the
partnership under agreement. See "Transactions with the
Managing
General Partner or Affiliates ," below.
Conflicting Drilling Activities. Our affiliates have engaged in
significant drilling and producing activities for the accounts of affiliated
partnerships related to previous drilling programs. In addition, we and our
affiliates manage and operate gas properties for investors in other
drilling programs. Although the limited partnership agreement attempts to
minimize any potential conflicts, we 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 we or our affiliates may
presently operate or operate in the future.
Conflicts with Other Programs. We realize that our conduct and the
conduct
of our 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 additional programs. In resolving any
conflicts, each partnership will be treated equitably with
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.
We
believe 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 we or an
affiliate
serves as general partner have been committed to a specific drilling
program.
We follow a policy of developing next what we judge 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. We
anticipate
that generally only one partnership will be actively engaged in
drilling
at any time. However, 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 our 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 limited partnership agreement authorizes us to cause the
partnership to acquire undivided interests in natural gas properties,
and
to participate with other parties, including other drilling programs
previously
or subsequently conducted by us or our affiliates, in the conduct of
exploration
and drilling operations on those properties. Because we must deal fairly
with
the investors in all of our drilling programs, if conflicts between the
interest
of the partnership and other drilling programs do arise, we
might
not in every instance be able to resolve those conflicts to the maximum
advantage
of the partnership .
From time to time, we 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 acquisition can be
made
from the capital contributions. the property is not
acquired
by the partnership may lose a promising prospect. Except as
otherwise
provided by the limited partnership agreement, prospect might be
acquired by us or an affiliate or other drilling programs conducted by them.
In addition, subject to the restrictions set forth below, we in our
sole
discretion decide which prospects and what interest to transfer to
the
partnership . This may result in another drilling program sponsored
by us
acquiring property adjacent to partnership property.
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
other drilling program were the first to discover or develop a
productive
pool of oil or natural gas.
Acquisition of Prospects. We have discretion in selecting leases to
be
acquired by the partnership from us or our affiliates or third
parties and
the location and type of operations which the partnership will
conduct on
leases. leases may be part of our existing inventory,
although
no leases have been designated for inclusion in the partnership at
the
present time. Neither we nor any affiliate will retain undeveloped acreage
adjoining a partnership prospect in order to use partnership
funds
to "prove up" the acreage owned for our own account.
Whenever we sell, transfer or convey an interest in a prospect to a
particular partnership , we must, at the same time, sell to the
partnership an equal proportionate interest in all of our leases in
the
same prospect (except any interests in producing wells). If we or an
affiliate
(except another affiliated limited partnership in which the interest of us
or our
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 prospect acquisition,
we or
affiliate will offer an equivalent interest to the
partnership ; and, if cash or financing is not available to
to
enable it to consummate a purchase of an equivalent interest in
property, neither we nor any of our affiliates will acquire
interest
or property, but the term "affiliate" will not include another partnership
where
our or our 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 our or our affiliates' interest in any prospect is prohibited unless the
interest retained by us or our affiliates is a proportionate working
interest,
the respective obligations of the partnership and us or our
affiliates are
substantially the same immediately after the sale of the interest, and our
or our
affiliates' interest in revenues does not exceed an amount proportionate to
the
retained working interest. Neither we nor our 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 our retained interest, except to non-affiliated third parties.
The partnerships will acquire only those leases reasonably
expected
to meet the stated purposes of 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
acquisition would be in the partnerships' best interest. We
expect
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 we, exercising the standard of a
prudent
operator, determine that:
a partnership lacks sufficient funds to drill
on
the lease and cannot obtain suitable alternative financing;
downgrading subsequent to a partnership's
acquisition has rendered drilling undesirable;
drilling would concentrate excessive funds in one
location creating undue risk to a partnership or
the best interests of a partnership , based on the
standard of
a prudent operator, would be served by disposition. In the event
of a
farmout, we will retain for the partnerships economic interests and
concessions as a reasonably prudent operator would retain under the
circumstances. We will not farm out a lease for the primary purpose of
avoiding
payments of our partnership share of costs of drilling on that lease.
However, the decision with respect to making farmouts and the terms of a
farmout
involve conflicts of interest because we may benefit from cost savings and
reduction of risk, and in the event of a farmout to an affiliated limited
partnership or other affiliate, we or our affiliates will represent both
related
entities.
Transactions with the Managing General Partner or Affiliates. We will
furnish drilling and completion services with respect to some or all of the
partnership wells. A subsidiary of ours may market gas produced from
partnership wells. In addition, we will act as operator for the
producing
wells of the partnership . The prices to be charged the
partnership
for supplies and services will be competitive with the prices of
other
unaffiliated persons in the same geographic area engaged in similar
businesses.
We expect to earn a profit for services.
Neither we nor any affiliate 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 person is engaged,
independently
of the partnership and as an ordinary and ongoing business, in the
business of rendering services or selling or leasing
equipment
and supplies to a substantial extent to other persons in the gas industry
in
addition to partnerships in which we or our affiliate has an interest, or,
if
person is not engaged in business then compensation,
price
or rental will be the cost of services, equipment or supplies to
person or the competitive rate which could be obtained in the area,
whichever
is less. Notwithstanding any provision to the contrary, we and our
affiliates
may not profit by drilling in contravention of our fiduciary obligations to
the
investor partners . Any services not otherwise described in this
prospectus for which we or any of our 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 us or our 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 us or any affiliate.
We or any affiliate, other than other programs sponsored by us or our
affiliates, may not purchase the partnerships' producing properties.
Conflict in Establishing Unit Repurchase Price. Under our unit
(See "Terms of the Offering - Unit Repurchase Program" above , we,
once
we have received a request from an investor partner that we
repurchase
that partner's, will establish an offering price. We will determine
the
offering price which will not necessarily represent the fair market value
of the
units . In setting the price, we will consider our available funds
and our
desire to acquire production as represented by the units . A conflict
will
arise in that the price set will be that which we consider to be in our 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.
Certain Transactions
<TABLE>
<C> <C> <C> <C> <C> <C> <C>
As of September 30, 2000, previous limited partnerships sponsored by
us
have made payments to us or our affiliates as follows:
Footage
and Daywork
Drilling
Contracts,
Turnkey Services, General
Non- Drilling Chemicals, and
Recurring and Supplies
Administrative
Name of Management Sales Completion and Operators
Expense
Partnership Fee of Leases Contracts Equipment Charges
Reimbursement
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 14,079 715 459,153 -- -- -----
PDC 1988 23,842 17,150 -- 708,200 72,534 --
PDC 1988-B 6,053 6,450 -- 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 5,150 62,209 -- 1,265,680 -- --
PDC 1990-B 55,525 72,100 -- 2,025,511 -- --
PDC 1990-C 86,950 117,215 -- 3,167,563 -- --
PDC 1990-D 92,138 137,225 3,343,524 -- -- -
PDC 1991-A 68,475 75,193 -- 2,511,640 -- --
PDC 1991-B 46,587 62,209 -- 1,697,764 -- --
PDC 1991-C 68,400 70,235 -- 2,513,765 -- --
PDC 1991-D 31,463 153,721 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 59,722 149,657 -- 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 -- --
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 467,734 795,958 19,550,451 -- -- --
PDC 2000-A(1) 123,918 74,291 -- 5,316,140 -- --
PDC 2000-B(2) 290,070 140,250 9,951,154 -- --
--------------------
</TABLE>
[FN]
(1) Partnership funded in May 2000.
(2) Partnership funded in September 2000
</FN>
FIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNERFIDUCIARY
RESPONSIBILITY OF THE MANAGING GENERAL PARTNERFIDUCIARY RESPONSIBILITY OF
THE
MANAGING GENERAL PARTNERFIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL
PARTNERFIDUCIARY RESPONSIBILITY OF THE MANAGING GENERAL PARTNERFIDUCIARY
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 limited 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.
We are accountable to the partnerships as a fiduciary and
consequently must exercise utmost good faith and integrity in handling
partnership affairs. Under West Virginia law, we will owe the
investor
partners a duty of utmost good faith, fairness, and loyalty. In this
regard,
we are 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, we 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
our
responsibilities as 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 the 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 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 , we, depending upon the particular
circumstances
involved, might be able to avail ourselves under West Virginia law of
various
defenses to the lawsuit, including statute of limitations, estoppel, laches,
and
doctrines such as the "clean hands" doctrine.
The limited 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 the 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. We may not be
indemnified for any such liability arising out of a breach of our duty to
the
partnership or our negligence, fraud, bad faith or misconduct in the
performance of our fiduciary duty. The limited 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, we 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) the 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 the 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 (a) which are specifically set forth in the
prospectus and
(b) 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 these
indemnification provisions, a purchaser of units may have a more
limited
right of legal action than he would have if provision were not
included
in the limited partnership agreement. To the extent that the
indemnification
provisions purport to include indemnification for liabilities arising under
the
Securities Act of 1933 in the opinion of the Securities and Exchange
Commission, this indemnification is against public policy as
expressed in
the Securities Act, and is, therefore, unenforceable.
The limited 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 the party is prohibited from
being
indemnified.
PRIOR ACTIVITIESPRIOR ACTIVITIESPRIOR ACTIVITIESPRIOR
ACTIVITIESPRIOR
ACTIVITIESPRIOR ACTIVITIES
Prior PartnershipsPrior PartnershipsPrior PartnershipsPrior
PartnershipsPrior
PartnershipsPrior Partnerships
Petroleum Development Corporation ("PDC"), as general partner, has
previously sponsored ten private and nine public drilling programs. PDC
2003
Drilling Program is the tenth public drilling program sponsored by
PDC
as general partner. The various drilling programs sponsored by PDC have
raised
a total of over $250 million.
Each of the previous 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. You should not assume that you will experience
returns, if
any, comparable to those experienced by investors in prior programs.
<TABLE>
<C> <C> <C> <C> <C> <C>
<C>
The following table is presented to indicate certain sale
characteristics
concerning previous gas limited partnerships sponsored by the Managing
General
Partner and its Affiliates.
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 --
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 11/97 208.34 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 5/00 354.38 20,000 7,087,559 --
PDC 1999-D 12/99 7/00 935.47 20,000 18,709,342 --
PDC 2000-A 5/00 11/00(2) 247.84 20,000 4,956,718 --
PDC 2000-B 9/00 3/01(3) 580.14 20,000 11,602,809 --
--------------
</TABLE>
[FN]
(1) Cash distribution made each month since date of
first
distribution.
(2) Partnership closed on May 22, 2000. Wells were
drilled
in the second and third quarters of 2000; first revenue distribution to
commence
in November, 2000.
(3) Partnership closed on September 13, 2000. Wells
were
drilled in the third and fourth quarters of 2000; first revenue distribution
to
commence in March, 2001.
</FN>
You should not consider operating results obtained by these prior
partnerships as indicative of the operating results obtainable by the
partnerships.
Previous Drilling Activities
The following table reflects the drilling activity of previous
limited partnerships sponsored by the Managing General Partner and its
Affiliates
as of September 30, 2000. All of the wells drilled were Development Wells,
except as otherwise noted.
Productive Well Table
September 30, 2000
<TABLE>
<C> <C> <C>
<C> <C> <C> <C>
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
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(4) 5 - 62.3 4.3
PDC 1997-A - 21(5) 1 - 11.1 0.1
PDC 1997-B - 34(6) 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(7) 8(8) - 70.8(7) 7.6(8)
PDC 1999-A - 24 0 - 19.5 0
PDC 1999-B - 26 1 - 21.0 0.5
PDC 1999-C - 24 2 - 20.9 2.0
PDC 1999-D - 51 0 - 37.5 0
PDC 2000-A(9) - 13 0 - 10.28 0
PDC 2000-B(10) - 8 0 - 6.30 0
Total ...... 41 1,148 92 41 932.78 80.2
---------------------
</TABLE>
[FN]
(1) Gross wells include all wells in which the
partnerships
owned a Working Interest.
(2) Net wells are the number of gross wells multiplied
by the
percentage Working Interest owned by the partnerships in the gross wells.
(3) The dry hole indicated represents an exploratory
well.
(4) Ten wells in the Angel Antrim Shale Project were
productive wells and subsequently plugged in third quarter of 2000.
(5) Three wells in the Angel Antrim Shale Project were
productive wells and subsequently plugged in the third quarter of 2000.
(6) Six wells in the East 23 Antrim Shale Project were
productive wells and subsequently plugged in the third quarter of 2000.
(7) One of the gas wells represents an exploratory well
with
a net interest of .9.
(8) Three of the dry holes represent exploratory wells
with
a net interest of 2.7.
(9) Partnership funded in May 2000. Wells were drilled
in
the second and third quarters of 2000.
(10)Partnership funded in September 2000. Wells were drilled in third
and
fourth quarters of 2000.
</FN>
You should not consider operating results obtained by these prior
partnerships as indicative of the operating results obtainable by the
partnerships.
Payout and Net Cash Tables
The following tables provide information concerning the operating
results of previous limited partnerships sponsored by the Managing
General
Partner and its Affiliates as of September 30, 2000.
<TABLE>
<C> <C> <C> <C>
<C>
Participants' Payout Table
September 30, 2000
Revenues Before Deducting
Operating Costs(3)
Total
Expendi-
tures Total During Three
Investors' I ncluding As of Months Ended
Funds Operating Sept 30, Sept 30,
Partnership Invested(1) Costs(2) 2000 2000
Pennwest Petroleum
Group 1984 $2,093,125 $3,243,979 $2,163,801 $ 8,099
Pennwest Petroleum
Group 1,976,250 3,097,127 1,786,112 14,316
Petrowest Gas Group
1986-A 956,250 1,549,690 1,018,465 8,527
Petrowest Gas Group
1987 1,143,250 1,884,809 1,504,069 13,820
Petrowest Gas Group
1987-B 983,875 1,487,076 784,258 6,627
PDC 1987 454,750 730,237 529,230 4,394
PDC 1988 770,100 1,282,472 1,123,674 8,612
PDC 1988-B 841,500 1,294,575 590,711 6,577
PDC 1988-C 1,326,000 2,077,972 1,151,325 15,071
PDC 1989-P 1,523,625 2,379,810 1,756,180 17,721
PDC 1989-A 1,028,500 1,668,596 1,327,356 20,213
PDC 1989-B 3,153,500 4,646,093 2,629,879 25,749
PDC 1990-A 1,195,100 1,695,732 713,374 7,208
PDC 1990-B 1,887,850 2,795,689 1,545,021 19,249
PDC 1990-C 2,956,300 4,353,842 2,270,149 47,167
PDC 1990-D 3,132,674 4,530,775 2,278,193 35,793
PDC 1991-A 2,328,150 3,397,679 2,059,586 26,107
PDC 1991-B 1,583,975 2,248,751 1,172,142 18,239
PDC 1991-C 2,325,600 3,341,139 1,820,720 29,154
PDC 1991-D 4,469,725 6,251,223 2,499,763 47,750
PDC 1992-A 2,472,396 3,388,875 1,001,546 16,350
PDC 1992-B 2,532,246 3,622,194 2,139,856 39,422
PDC 1992-C 5,430,563 7,837,725 5,315,774 92,378
PDC 1993-A 2,647,750 4,042,524 3,955,909 46,097
PDC 1993-B 2,130,620 2,855,887 1,268,475 26,739
PDC 1993-C 2,665,865 3,587,352 1,373,735 35,228
PDC 1993-D 2,545,375 3,340,033 1,461,711 36,767
PDC 1993-E 6,438,950 7,941,170 3,559,561 81,591
PDC 1994-A 1,798,563 2,445,889 885,089 18,989
PDC 1994-B 2,353,579 3,092,479 1,366,929 38,908
PDC 1994-C 2,052,636 2,676,111 1,033,025 29,514
PDC 1994-D 6,605,166 8,541,330 3,355,374 94,874
PDC 1995-A 1,282,403 1,720,767 801,135 21,238
PDC 1995-B 1,625,442 2,030,693 566,296 15,968
PDC 1995-C 1,850,184 2,384,000 702,715 22,615
PDC 1995-D 7,137,437 8,998,268 2,881,833 101,455
PDC 1996-A 2,241,294 2,889,680 1,506,880 45,978
PDC 1996-B 2,335,695 2,935,422 1,141,600 44,730
PDC 1996-C 3,433,436 4,207,650 1,220,517 52,741
PDC 1996-D 13,312,502 16,239,367 4,377,034 264,983
PDC 1997-A 3,625,243 4,358,220 1,048,643 54,289
PDC 1997-B 5,880,739 7,043,149 1,374,571 72,489
PDC 1997-C 5,257,634 6,400,198 1,746,468 149,909
PDC 1997-D 16,112,034 19,618,816 2,936,148 268,770
PDC 1998-A 4,586,758 5,619,947 1,149,084 149,450
PDC 1998-B 6,216,237 7,559,196 1,455,863 247,245
PDC 1998-C 6,797,121 8,302,405 1,513,966 211,539
PDC 1998-D 17,856,977 21,318,008 2,446,562 397,439
PDC 1999-A 4,176,643 4,955,837 669,943 170,696
PDC 1999-B 4,819,707 5,759,272 938,884 275,520
PDC 1999-C 6,166,176 7,300,098 928,314 421,424
PDC 1999-D 16,277,127 18,915,894 1,385,050 1,154,893
PDC 2000-A(4) 4,312,345 5,001,114 330,203
PDC 2000-B(5) 10,094,444 11,602,809 - -
---------------------
</TABLE>
[FN]
(1) Total Subscriptions, less commissions, management
fee,
and offering costs.
(2) Includes the total of the subscriptions, assessments,
funds
advanced by the Managing General Partner to the general or limited
partnerships,
inclusive of operating costs. None of the partnerships has borrowed any
funds.
(3) Represents the accrued gross revenues credited to
the
participants from oil and gas revenues net of royalties to landowners,
overriding
royalty interest, and other burdens, excluding interest income.
(4) Partnership funded in May 2000; wells were drilled
in the
second and third quarters of 2000; first revenue distribution to commence
in
November, 2000.
(5)Partnership funded in September 2000; wells were
drilled in
the third and fourth quarters of 2000; first revenue distribution to
commence in
March, 2001.
</FN>
You should not consider operating results obtained by these prior
partnerships as indicative of the operating results obtainable by the
partnerships.
<TABLE>
Participants' Net Cash Table
September 30, 2000
<C> <C> <C>
<C> <C> <C>
<C>
<C>
Total Revenues
After Deducting Cash
Operating Costs(3) Distributions(4)
Total Three Three Aggregate-
Investors' Expenditures- Total Months Total Months
Section
29
Partnership- Funds Net of As of Ended As of Ended Tax Credits(5)
Invested (1) Operating- Sept Sept 30, Sept 30, Sept 30,
Costs(2) 30, 2000 2000 2000
Pennwest Petroleum
Group 1984 $2,093,125 $2,462,500 $1,382,322 $ 493 $1,312,820 $
$
493$536,186
Pennwest Petroleum
Group 1985-A 1,976,250 2,325,000 1,013,985 796 970,713
796651,854
Petrowest Gas
Group 1986-A 956,250 1,125,000 593,775 1,524 567,005
1,524467,451
Petrowest Gas
Group 1987 1,143,250 1,345,000 964,260 2,743 921,640
2,743528,770
Petrowest Gas
Group 1987-B 983,875 1,157,500 454,682 806 428,312
806368,780
PDC 1987 454,750 535,000 333,993 750 316,421 750236,910
PDC 1988 770,100 906,000 747,202 2,047 710,313
2,047482,543
PDC 1988-B 841,500 990,000 286,136 663 262,296 663265,608
PDC 1988-C 1,326,000 1,560,000 633,353 990 590,297 990504,653
PDC 1989-P 1,523,625 1,792,500 1,168,870 5,264 1,090,985
5,264792,113
PDC 1989-A 1,028,500 1,210,000 868,760 11,493 825,676
11,493549,988
PDC 1989-B 3,153,500 3,710,000 1,693,797 5,766 1,588,151
5,766780,206
PDC 1990-A 1,195,100 1,406,000 423,642 1,545 363,429
1,545143,138
PDC 1990-B 1,887,850 2,221,000 970,332 2,640 932,572
2,640634,389
PDC 1990-C 2,956,300 3,478,000 1,394,307 20,178 1,325,069
20,178651,548
PDC 1990-D 3,132,674 3,685,500 1,432,918 12,473 1,372,051
12,473837,696
PDC 1991-A 2,328,150 2,739,000 1,400,907 5,279 1,297,442
5,279860,839
PDC 1991-B 1,583,975 1,863,500 786,890 7,659 758,015
7,659502,273
PDC 1991-C 2,325,600 2,736,000 1,215,580 10,915 1,128,980
10,915765,865
PDC 1991-D 4,469,725 5,258,500 1,507,040 15,814 1,434,028
15,814986,968
PDC 1992-A 2,472,396 2,908,700 521,371 3,548 442,647
3,548383,855
PDC 1992-B 2,532,246 2,979,100 1,496,762 17,415 1,435,705
17,415909,400
PDC 1992-C 5,430,563 6,388,900 3,866,948 44,298 3,744,834
44,2981,769,675
PDC 1993-A 2,647,750 3,026,000 2,939,384 20,054 2,745,208
20,054131,415
PDC 1993-B 2,130,620 2,435,000 847,588 11,646 788,681
11,646
--
PDC 1993-C 2,665,865 3,046,700 833,083 13,710 776,697
13,710--
PDC 1993-D 2,545,375 2,909,000 1,030,678 17,716 989,440
17,716--
PDC 1993-E 6,438,950 7,358,800 2,977,192 37,282 2,828,244
37,282--
PDC 1994-A 1,798,563 2,055,500 494,700 5,757 454,730 5,757--
PDC 1994-B 2,353,579 2,689,804 964,254 18,981 908,996
18,981--
PDC 1994-C 2,052,636 2,345,870 702,784 14,070 646,347
14,070--
PDC 1994-D 6,605,166 7,548,761 2,362,806 49,606 2,175,951
49,606
--
PDC 1995-A 1,282,403 1,465,603 545,971 11,452 497,912
11,452--
PDC 1995-B 1,625,442 1,857,648 393,252 6,707 337,244 6,707 --
PDC 1995-C 1,850,184 2,114,496 433,211 6,438 376,414 6,438--
PDC 1995-D 7,137,437 8,157,071 2,040,637 49,580 1,829,941
49,580--
PDC 1996-A 2,241,294 2,576,200 1,193,400 25,355 1,058,582
25,355--
PDC 1996-B 2,335,695 2,684,707 890,885 22,524 765,969
22,524--
PDC 1996-C 3,433,436 3,946,478 977,345 25,266 860,070
25,266--
PDC 1996-D 13,312,502 15,301,726 3,439,393 234,876 3,081,303
234,876--
PDC 1997-A 3,625,243 4,166,946 857,368 31,256 763,447
31,256--
PDC 1997-B 5,880,739 6,759,470 1,090,892 36,895 941,491
36,895--
PDC 1997-C 5,257,634 6,043,257 1,389,527 159,310 1,067,616
159,310---
PDC 1997-D 16,112,034 18,519,579 1,836,911 125,731 1,453,026
125,731--
PDC 1998-A 4,586,758 5,272,135 801,273 98,538 650,246
98,538--
PDC 1998-B 6,216,237 7,145,101 1,041,768 172,509 948,370
172,509--
PDC 1998-C 6,797,121 7,812,783 1,024,345 123,700 758,688
123,700--
PDC 1998-D 17,856,977 20,525,261 1,653,815 231,479 1,192,251
231,479--
PDC 1999-A 4,176,643 4,800,739 514,844 124,777 375,255
124,777--
PDC 1999-B 4,819,707 5,539,893 719,504 208,903 532,300
208,903--
PDC 1999-C 6,166,176 7,087,559 715,775 343,855 474,453
343,855--
PDC 1999-D 16,277,127 18,709,342 1,178,498 991,195 991,195
991,195--
PDC 2000-A(6) 4,312,345 4,956,718 285,807 - - - -
--
PDC 2000-B(7) 10,094,444 11,602,809 -- - -- -- --
---------------------
</TABLE>
[FN]
(1) Total Subscriptions, less commissions, management
fee,
and offering costs.
(2) Includes the total of the subscriptions,
assessments,
funds advanced by the Managing General Partner to the general or limited
partnerships, exclusive of operating costs. None of the partnerships has
borrowed any funds.
(3) Represents the accrued gross revenues credited from
oil
and gas production, excluding operating costs, landowners' royalty
interests,
overriding royalty interests, and other burdens.
(4) Represents the net cash distributed to the
partnerships.
All cash distributions to the partners were made from operations and
constituted
ordinary income.
(5) Wells drilled after December 31, 1992 do not qualify
for
the credit.
(6) Partnership funded in May 2000; wells were drilled
in the
second and third quarters of 2000; first revenue distribution to commence
in
November, 2000.
(7) Partnership funded in September 2000; wells were
drilled
in the third and fourth quarters of 2000; first revenue distribution to
commence
in March, 2001.
</FN>
You should not consider operating results obtained by these prior
partnerships as indicative of the operating results obtainable by the
partnerships.
<TABLE>
<C> <C>
<C>
<C>
Managing General Partner's Payout Table
September 30, 2000
Revenues Before Deducting
Total Expenditures Operating Costs(2)
Including Total As of During Three Months
Partnership Operating Costs(1) Sept 30, 2000 Ended Sept 30, 2000
Pennwest Petroleum
Group 1984 $ 161,123 $276,481 $ 1,325
Pennwest Petroleum
Group 1985-A 150,942 236,297 2,340
Petrowest Gas
Group 1986-A 81,557 163,002 1,454
Petrowest Gas
Group 1987 99,197 232,581 2,293
Petrowest Gas
Group 1987-B 78,268 121,620 1,109
PDC 1987 38,436 82,765 742
PDC 1988 67,486 182,760 1,463
PDC 1988-B 68,138 97,604 1,129
PDC 1988-C 110,367 183,377 2,519
PDC 1989-P 125,247 275,230 2,948
PDC 1989-A 225,474 329,617 5,053
PDC 1989-B 565,148 633,536 6,437
PDC 1990-A 199,060 165,011 1,802
PDC 1990-B 349,611 376,195 4,812
PDC 1990-C 530,643 532,717 11,792
PDC 1990-D 537,538 513,769 8,948
PDC 1991-A 413,278 500,074 6,527
PDC 1991-B 262,989 283,056 4,560
PDC 1991-C 400,403 440,664 7,288
PDC 1991-D 718,273 578,305 11,937
PDC 1992-A 296,250 85,543 -0-
PDC 1992-B 431,376 524,545 9,856
PDC 1992-C 930,077 1,258,805 23,094
PDC 1993-A 500,950 859,684 10,119
PDC 1993-B 323,879 270,569 5,870
PDC 1993-C 397,648 259,360 7,733
PDC 1993-D 368,583 289,195 8,071
PDC 1993-E 822,685 719,471 17,910
PDC 1994-A 542,393 211,496 4,747
PDC 1994-B 685,491 332,548 9,727
PDC 1994-C 593,317 255,520 7,381
PDC 1994-D 1,888,871 812,718 23,615
PDC 1995-A 381,756 193,291 5,303
PDC 1995-B 446,002 131,145 3,985
PDC 1995-C 525,403 165,884 5,124
PDC 1995-D 1,978,086 677,008 22,338
PDC 1996-A 666,915 376,720 11,495
PDC 1996-B 695,396 285,400 11,183
PDC 1996-C 1,014,933 305,129 13,185
PDC 1996-D 3,995,186 1,094,258 66,246
PDC 1997-A 1,025,550 262,161 13,572
PDC 1997-B 1,668,584 343,641 18,122
PDC 1997-C 1,544,558 436,617 37,477
PDC 1997-D 4,414,231 734,036 67,192
PDC 1998-A 1,223,644 287,271 37,363
PDC 1998-B 1,657,585 363,965 61,811
PDC 1998-C 1,821,687 378,491 52,885
PDC 1998-D 4,662,433 611,640 99,360
PDC 1999-A 1,082,937 167,486 42,674
PDC 1999-B 1,259,773 234,721 68,880
PDC 1999-C 1,594,680 232,078 105,356
PDC 1999-D 4,120,920 346,262 288,723
PDC 2000-A(3) 1,089,185 82,551 -
PDC 2000-B(4) 2,523,611 - -
---------------------
</TABLE>
[FN]
(1) Includes Managing General Partner share of drilling
costs.
(2) Represents the accrued gross revenues credited to
the
managing general partner(s).
(3) Partnership funded in May 2000; wells were drilled
in the
second and third quarters of 2000; first revenue distribution to commence
in
November, 2000.
(4) Partnership funded in September 2000; wells were
drilled
during the third and fourth quarters of 2000; first revenue distribution to
commence in March, 2001.
</FN>
You should not consider operating results obtained by these prior
partnerships as indicative of the operating results obtainable by the
partnerships.
<TABLE>
<C> <C> <C>
<C> <C> <C>
<C>
Managing General Partner's Net Cash Table
September 30, 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 Sept Sept As of Sept Ended Sept Credits
Partnership Costs 30, 2000 30, 2000 30, 2000 30, 2000 (4)
Pennwest
Petroleum
Group 1984 $ 129,605 $244,963 $ 1,125 $241,305 $ 1,125
$28,220
Pennwest
Petroleum
Group 1985-A 122,368 207,723 1,985 205,446 1,985
34,308
Petrowest
Gas Group
1986-A 59,210 140,655 1,085 136,215 1,085
24,603
Petrowest
Gas Group
1987 70,789 204,173 1,710 197,961 1,710 27,830
Petrowest
Gas Group
1987-B 60,921 104,273 803 99,898 803 19,409
PDC 1987 28,158 72,488 550 69,844 550 12,469
PDC 1988 47,684 162,958 1,117 157,409 1,117 25,397
PDC 1988-B 52,105 81,571 818 76,964 818 13,979
PDC 1988-C 82,105 155,115 1,778 147,798 1,778 26,561
PDC 1989-P 94,342 244,325 2,292 230,937 2,292 41,690
PDC 1989-A 114,278 218,421 2,873 207,650 2,873 137,497
PDC 1989-B 350,389 418,777 1,441 392,368 1,441 195,051
PDC 1990-A 132,789 98,740 386 83,687 386 35,784
PDC 1990-B 209,761 236,345 660 226,905 660 158,597
PDC 1990-C 328,478 330,553 5,004 313,243 5,044 162,887
PDC 1990-D 348,075 324,306 3,118 309,089 3,118 209,424
PDC 1991-A 258,683 345,479 1,320 319,613 1,320 215,210
PDC 1991-B 175,997 196,064 1,915 190,289 1,915 125,568
PDC 1991-C 258,400 298,661 2,729 277,011 2,729 191,466
PDC 1991-D 496,639 356,670 3,953 338,417 3,953 246,742
PDC 1992-A 274,711 64,004 -0- 44,323 -0- -0-
PDC 1992-B 281,361 374,530 4,354 362,319 4,354 227,350
PDC 1992-C 603,396 932,124 11,074 907,702 11,074
442,419
PDC 1993-A 294,194 652,928 4,402 610,304 4,402 29,568
PDC 1993-B 236,736 183,426 2,556 170,495 2,556 --
PDC 1993-C 296,207 157,919 3,009 145,542 3,009 --
PDC 1993-D 282,819 203,431 3,889 194,379 3,889 --
PDC 1993-E 715,438 612,224 8,184 579,528 8,184 --
PDC 1994-A 449,641 118,743 1,439 109,969 1,439 --
PDC 1994-B 588,395 235,453 4,745 221,638 4,745 --
PDC 1994-C 513,159 175,362 3,517 161,253 3,517 --
PDC 1994-D 1,651,292 575,139 12,348 528,425 12,348 --
PDC 1995-A 320,601 132,136 2,863 120,121 2,863 --
PDC 1995-B 406,361 91,504 1,677 77,502 1,677 --
PDC 1995-C 462,546 103,028 1,441 88,829 1,441 --
PDC 1995-D 1,784,359 483,281 10,913 430,607 10,913 --
PDC 1996-A 560,324 270,129 6,339 236,425 6,339 --
PDC 1996-B 583,924 173,928 5,631 142,699 5,631 --
PDC 1996-C 858,359 148,556 6,316 119,237 6,316 --
PDC 1996-D 3,328,126 427,199 (37,898)(7) 337,677 (37,898)(7)--
PDC 1997-A 906,311 142,921 7,814 119,441 7,814 --
PDC 1997-B 1,470,185 145,243 9,224 107,893 9,224 --
PDC 1997-C 1,314,409 206,467 (26,125)(7) 125,989 (26,125)(7) --
PDC 1997-D 4,028,009 347,814 31,432 251,843 31,432 --
PDC 1998-A 1,146,758 200,317 24,634 162,560 24,634 --
PDC 1998-B 1,554,059 260,440 43,127 237,091 43,127 --
PDC 1998-C 1,699,280 256,084 30,925 189,670 30,925 --
PDC 1998-D 4,464,244 413,451 57,869 298,060 57,869 --
PDC 1999-A 1,044,161 128,710 31,194 93,813 31,194 --
PDC 1999-B 1,204,927 179,875 52,225 133,074 52,225 --
PDC 1999-C 1,541,544 178,943 85,963 118,613 85,963 --
PDC 1999-D 4,069,282 294,624 247,798 247,798 247,798 --
PDC 2000-A(5) 1,078,086 71,452 - -- -- --
PDC 200-B(6) 2,523,611 -- - -- -- --
---------------------
</TABLE>
[FN]
(1) Includes Managing General Partner share of drilling
costs, exclusive of operating costs.
(2) Represents the accrued gross revenues credited from
oil
and gas production, excluding operating costs, landowners' royalty
interests,
Overriding Royalty Interests, and other burdens.
(3) Represents the net cash received from the
partnerships'
cash distributions. All cash distributions to the managing general partner
were
made from operations.
(4) Wells drilled after December 31, 1992 do not qualify
for
the credit.
(5) Partnership funded in May 2000; wells were drilled
in the
second and third quarters of 2000; first revenue distribution to commence
in
November, 2000.
(6) Partnership funded in September 2000; wells were
drilled
in the third and fourth quarters of 2000; first revenue distribution to
commence
in March, 2001.
(7) Reflects payment for preferred cash distribution paid to
investing
partners.
</FN>
You should not consider operating results obtained by these prior
partnerships as indicative of the operating results obtainable by the
partnerships.
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 the share of tax deductions as a
percentage
of their subscriptions. The following percentages do not reflect the effect
of
the revenues from the partnerships' operations and are subject to audit
adjustments by the Service. The table also reflects the aggregate Section
29
nonconventional fuel production credit as a percentage of the participants'
initial investment over the life of each partnership through September 30,
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>
<C> <C> <C>
<C> <C> <C>
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% 27.22% 21.77% 68.39% 1.4:1
*Pennwest
Petroleum
Group 1985-A 69.51% 28.27% 28.04% 73.45%
1.5:1
*Petrowest
Gas Group
1986-A 70.10% 28.91% 41.55% 86.69% 1.8:1
*Petrowest
Gas Group
1987 63.09% 34.09% 39.31% 75.19% 2.3:1
*Petrowest
Gas Group
1987-B 68.70% 26.85% 31.86% 67.40% 2.1:1
*PDC 1987 70.30% 32.67% 44.28% 82.51% 2.6:1
*PDC 1988 68.57% 33.62% 53.26% 87.37% 2.9:1
*PDC 1988-B 66.70% 32.59% 26.83% 60.08% 1.9:1
*PDC 1988-C 69.20% 30.50% 32.35% 65.75% 2.1:1
*PDC 1989-P 63.68% 31.73% 44.19% 76.31% 2.5:1
*PDC 1989-A 69.80% 35.78% 45.45% 81.22% 2.6:1
*PDC 1989-B 69.10% 28.77% 21.03% 53.92% 1.7:1
*PDC 1990-A 67.92% 19.03% 10.18% 39.29% 1.2:1
*PDC 1990-B 71.50% 23.56% 28.56% 60.58% 2.0:1
*PDC 1990-C 70.60% 26.95% 18.73% 51.81% 1.6:1
*PDC 1990-D 69.70% 29.44% 22.73% 56.45% 1.8:1
*PDC 1991-A 69.80% 22.52% 31.43% 61.45% 2.0:1
*PDC 1991-B 67.00% 27.18% 26.95% 57.50% 1.9:1
*PDC 1991-C 69.60% 27.56% 27.99% 59.81% 2.0:1
*PDC 1991-D 69.80% 23.74% 18.77% 49.29% 1.6:1
*PDC 1992-A 68.24% 18.23% 13.20% 41.40% 1.3:1
*PDC 1992-B 69.60% 29.08% 30.53% 63.43% 2.1:1
*PDC 1992-C 69.20% 31.63% 27.70% 61.46% 2.0:1
*PDC 1993-A 69.00% 40.24% 4.34% 41.43% 1.2:1
*PDC 1993-B 68.10% 25.57% -- 34.62% 0.9:1
*PDC 1993-C 68.80% 23.97% -- 34.26% 0.9:1
*PDC 1993-D 68.60% 22.11% -- 33.44% 0.9:1
*PDC 1993-E 67.60% 25.54% -- 34.44% 0.9:1
*PDC 1994-A 87.70% 5.25% -- 36.81% 0.9:1
*PDC 1994-B 89.40% 7.15% -- 38.23% 1.0:1
*PDC 1994-C 89.70% 5.97% -- 37.88% 1.0:1
*PDC 1994-D 89.90% 6.69% -- 38.25% 1.0:1
*PDC 1995-A 85.66% 12.89% -- 39.02% 1.0:1
*PDC 1995-B 89.02% 5.91% -- 37.59% 0.9:1
PDC 1995-C 89.71% 5.45% -- 37.68% 1.0:1
PDC 1995-D 89.94% 5.52% -- 37.80% 1.0:1
PDC 1996-A 89.94% 7.62% -- 38.64% 1.0:1
PDC 1996-B 86.82% 8.29% -- 37.66% 1.0:1
PDC 1996-C 89.42% 4.90% -- 37.35% 0.9:1
PDC 1996-D 89.49% 4.54% -- 37.24% 0.9:1
PDC 1997-A 89.50% 3.15% -- 36.69% 0.9:1
PDC 1997-B 89.50% 3.08% -- 36.66% 0.9:1
PDC 1997-C 89.50% 4.43% -- 37.20% 0.9:1
PDC 1997-D 89.50% 2.87% -- 36.58% 0.9:1
PDC 1998-A 89.50% 3.44% -- 36.80% 0.9:1
PDC 1998-B 89.50% 3.95% -- 37.01% 0.9:1
PDC 1998-C 89.50% 3.09% -- 36.66% 0.9:1
PDC 1998-D 89.50% 1.91% -- 36.20% 0.9:1
PDC 1999-A 89.50% 1.04% -- 35.85% 0.9:1
PDC 1999-B 89.50% 1.07% -- 35.87% 0.9:1
PDC 1999-C 89.50% 0.60% -- 35.68% 0.9:1
PDC 1999-D 89.50% 0.20% -- 35.52% 0.9:1
PDC 2000-A(4) 89.50% 0.00% -- 35.44% 0.9:1
PDC 2000-B(5) 89.50% 0.00% -- 35.44% 0.9:1
</TABLE>
*Partnerships in existence for over five years.
---------------------
[FN]
(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
t afterward.
(3) Total deductions plus 200% of credits generated for
partnerships first offered before December 31, 1986. Total deductions plus
350%
of credits generated for partnerships offered after December 31, 1986.
(4) Partnership funded in May 2000.
(5) Partnership funded in September 2000.
</FN>
You should not consider operating results obtained by these prior
partnerships as indicative of the operating results obtainable by the
partnerships.
<TABLE>
Percentage of Gross Return on Subscriptions Through
September 30, 2000
From Cash Distributions, Tax Savings from
Deductions and Tax Credits(1)
<C> <C>
<C> <C> <C>
<C> <C>
Tax Total
Cumulative Total Cash Deductions Return of Year/
Cash Section 29 and Tax Cash, Tax Months
Program Distributions Credit(3) Tax Credit Effected(4)
Deduction(5) Producing
*Pennwest Petroleum
1984 53.28% 21.77% 75.05% 50.54% 125.59% 15/6
*Pennwest Petroleum
1985-A 41.52% 28.04% 69.56% 49.32% 118.88% 14/7
**Petrowest Gas
Group 1986 50.14% 41.55% 91.70% 49.10% 140.79%
13/6
**Petrowest Gas
Group 1987 68.28% 39.31% 107.60% 39.76% 147.36%
12/9
**Petrowest Gas
Group 1987-B 36.92% 31.86% 68.78% 39.37% 108.15%
12/6
**PDC 1987 58.84% 44.28% 103.13% 42.35% 145.47% 12/4
**PDC 1988 77.64% 53.26% 130.91% 38.19% 169.10%
11/10
**PDC 1988-B 26.45% 26.83% 53.28% 37.23% 90.50%
11/6
**PDC 1988-C 37.74% 32.35% 70.08% 37.39% 107.47%
11/4
**PDC 1989-P 60.21% 44.19% 104.40% 35.94% 140.34%
10/10
**PDC 1989-A 67.87% 45.45% 113.33% 39.99% 153.32%
10/6
**PDC 1989-B 42.61% 21.03% 63.64% 36.80% 100.44%
10/4
**PDC 1990-A 25.85% 10.18% 36.03% 32.59% 68.62%
9/11
**PDC 1990-B 41.79% 28.56% 70.36% 35.82% 106.18%
9/9
**PDC 1990-C 37.74% 18.73% 56.47% 36.97% 93.45%
9/5
**PDC 1990-D 37.03% 22.73% 59.76% 37.69% 97.45%
9/4
**PDC 1991-A 47.22% 31.43% 78.64% 33.81% 112.45%
8/11
**PDC 1991-B 40.39% 26.95% 67.34% 34.31% 101.65%
8/8
**PDC 1991-C 40.94% 27.99% 68.93% 35.70% 104.63%
8/6
**PDC 1991-D 27.13% 18.77% 45.90% 34.26% 80.16%
8/4
**PDC 1992-A 15.22% 13.20% 28.42% 31.67% 60.08%
7/11
**PDC 1992-B 47.59% 30.53% 78.12% 36.85% 114.97%
7/9
**PDC 1992-C 57.52% 27.70% 85.22% 37.79% 123.01%
7/6
**PDC 1993-A 89.06% 4.34% 93.41% 41.45% 134.86% 7/4
**PDC 1993-B 32.12% -- 32.12% 38.36% 70.49% 6/11
**PDC 1993-C 22.29% -- 25.29% 37.97% 63.26% 6/8
**PDC 1993-D 33.41% -- 33.41% 36.06% 70.48% 6/6
**PDC 1993-E 37.74% -- 37.74% 38.16% 75.91% 6/3
**PDC 1994-A 21.49% -- 21.49% 40.53% 62.02% 5/11
**PDC 1994-B 32.63% -- 32.63% 42.10% 74.72% 5/8
**PDC 1994-C 26.96% -- 26.96% 41.71% 68.67% 5/6
**PDC 1994-D 27.80% -- 27.80% 42.11% 69.92% 5/4
**PDC 1995-A 32.81% -- 32.81% 42.97% 75.78% 5/0
**PDC 1995-B 17.56% -- 17.56% 41.39% 58.94% 4/9
**PDC 1995-C 17.23% -- 17.23% 41.49% 58.72% 4/6
**PDC 1995-D 22.17% -- 22.17% 41.62% 63.79% 4/4
**PDC 1996-A 39.75% -- 39.75% 42.54% 82.29% 3/11
**PDC 1996-B 26.81% -- 26.81% 41.47% 68.28% 3/7
**PDC 1996-C 20.080 -- 20.08% 41.12% 61.21% 3/5
**PDC 1996-D 17.96% -- 17.96% 41.00% 58.95% 3/4
**PDC 1997-A 17.13% -- 17.13% 40.40% 57.52% 2/11
**PDC 1997-B 12.63% -- 12.63% 40.37% 53.00% 2/7
**PDC 1997-C 15.98% -- 15.98% 40.96% 56.94% 2/5
**PDC 1997-D 7.40% -- 7.40% 40.27% 47.68% 2/3
**PDC 1998-A 12.26% -- 12.26% 40.52% 52.78% 1/10
**PDC 1998-B 13.13% -- 13.13% 40.75% 53.87% 1/7
**PDC 1998-C 9.59% -- 9.59% 40.37% 49.96% 1/5
**PDC 1998-D 5.76% -- 5.76% 39.86% 45.62% 1/3
**PDC 1999-A 7.82% -- 7.82% 39.47% 47.29% 0/11
*PDC 1999-B 9.61% -- 9.61% 39.49% 49.10% 0/7
*PDC 1999-C 6.69% -- 6.69% 39.28% 45.98% 0/5
*PDC 1999-D 5.30% -- 5.30% 39.11% 44.41% 0/3
*PDC 2000-A(6) 0.00% -- 0.00% 39.02% 39.02% 0/0
*PDC 2000-B(7) 0.00% -- 0.00% 39.02% 39.02% 0/0
* Program contains oil & gas production
** Program contains gas production
</TABLE>
---------------------
[FN]
(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 afterward .
(5) This column represents the sum of the percentage
amounts
set forth in columns 1, 2, and 4 of this table.
(6) Partnership funded in May 2000; wells were drilled
in the
second and the third quarters of 2000; first revenue distribution to
commence in
November, 2000.
(7) Partnership funded in September 2000; wells were
drilled
during the third and fourth quarters of 2000; first revenue distribution to
commence in March, 2001.
</FN>
You should not consider operating results obtained by these prior
partnerships as indicative of the operating results obtainable by the
partnerships.
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>
<C> <C>
<C> <C> <C>
<C>
Partnership Proved Reserves and Future Net Revenues
as of January 1, 2000(1)
Category ofEstimated Estimated Estimated Percent Value
PartnershipProved ReservesNet OilNet GasFuture NetDiscounted
BBL ReservesReserves Revenuesat 10% Annum
BblMCF
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
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
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
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 - - - -
PDC 2000-A(4).....Proved Developed - - - -
Proved Undeveloped - - - -
Totals - - - -
PDC 2000-B(4).....Proved Developed - - - -
Proved Undeveloped - - - -
Totals - - - -
</TABLE>
[FN]
(1) For the partnerships PDC 1989-A through PDC 1992-C
and
for PDC 1994-A through PDC 1998-C, we own 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,
we own 18% of the reserves listed and the investor partners own 82%
of the
reserves listed above.
(2) Reserve reports prepared by our petroleum engineers.
(3) Reserve reports prepared by an independent petroleum
consultant, Wright & Company, Inc.
(4) The wells of these partnerships were drilled after
December 31, 1999; therefore, reserve studies have not been conducted.
</FN>
You should not consider operating results obtained by these prior
partnerships
As indicative of the operating results obtainable by the partnerships
TAX CONSIDERATIONS
We attach the tax opinion of Duane, Morris & Heckscher LLP to the
prospectus as Appendix D. You should review Appendix D in its entirety
before
investing in the . 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 , which represent counsel's opinions
on
all material federal income tax consequences to the partnership and
to you
as an investor partner . There may be aspects of your particular tax
situation which are not addressed in the following discussion or in Appendix
D.
Additionally, the resolution of 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 these issues should be drawn
from
the following discussion.
The following statements are based upon the provisions of the Internal
Revenue Code of 1986, , 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 could be retroactive
with
respect to the transactions prior to the date of 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 and any 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 , 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 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 material federal
income tax issues as described more fully .
Summary of Conclusions
Opinions expressed: The following is a summary of the specific
opinions
expressed by counsel. To fully understand the tax considerations of an
investment in the , you should read the discussion of these matters
set
forth in the tax opinion in Appendix D.
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
as a
"publicly traded partnership." See "General Tax Effects of Partnership
Structure."
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 paid in 2001 with respect to the
partnerships designated "PDC 2001- Limited Partnership," in 2002 with
respect to the partnerships designated "PDC 2002- Limited
Partnership,"
and in 2003 with respect to the partnerships designated "PDC 2003-
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."
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 the general partner interest is so held will not be
limited by the passive activity provisions. See "Passive Loss and Credit
Limitations."
6. Limited partners interests (other than those held by
additional general partners who convert their interests into
limited
partners' interests) will be considered a passive activity within the
meaning
of Code Section 469 and losses generated therefrom will be limited by the
passive
activity provisions. See "Passive Loss and Credit Limitations."
7. The partnership will not be terminated solely as the
result
of the conversion of partnership interests. See "Conversion of
Interests."
8. To the extent provided in this section of the prospectus, the
partners' distributive shares of partnership tax items will
be
determined and allocated substantially in accordance with the terms of the
limited 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 .
See "Profit Motive."
3. Whether each partner will be entitled to percentage
depletion
since 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 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 from us, some
partners may choose to borrow the funds necessary to acquire a Unit
and
may incur interest expense in connection with that borrowing. Based upon
the
purely factual nature of any loans, counsel is unable to express an
opinion with respect to the deductibility of any interest paid or incurred
on
loans. See "Interest Deductions."
5. Whether the fees to be paid to us 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 treatment. See "Transaction Fees."
General Information: Certain matters contained in this
Considerations section are not considered to address a material
tax
consequence and are for general information, including the matters contained
in
sections dealing with gain or loss on the sale of units or of
property,
partnership distributions, tax audits, penalties, and state, local,
and
self-employment tax. See "General Tax Effects of Partnership Structure,"
"Gain
or Loss on Sale of Properties or Units," "Partnership Distributions,"
"Administrative Matters," "Accounting Methods and Periods," "Social Security
Benefits; Self-Employment Tax," and "State and Local Tax."
Facts and Representations: The opinions of counsel are also based
upon the
facts described in this prospectus and upon representations made to
counsel by us for the purpose of permitting counsel to render its opinions,
including the following representations with respect to the program:
1. The limited partnership agreement to be entered into
by
and among the investor partners and us and any amendments to the
agreement will be duly executed and will be made available to you upon
written
request. The limited partnership agreement will be duly recorded in all
places
required under the West Virginia Uniform Limited Partnership Act for
the
due formation of the partnership and for its continuation in
accordance
with the terms of the limited partnership agreement. The partnership
will
at all times be operated in accordance with the terms of the limited
partnership
agreement, the prospectus, and the Act.
2. No election will be made by the partnership,
or
us 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 amounts that will be paid to the Managing
General
Partner 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. We 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 between the partnership and us 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, 2002 for
partnerships
designated "PDC 2001- Limited Partnership" March 30, 2003 for
partnerships
designated "PDC 2002- Limited Partnership" and March 30, 2004 for
partnerships designated "PDC 2003- Limited Partnership."
8. The drilling and operating agreement will be duly
executed and will govern the operation of the partnership's wells.
9. Based upon our review of our experience with our
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 , we have represented that the sum of
the aggregate deductions, including depletion deductions, and
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 dates. In that regard, we have
reviewed
the economics of our similar oil and gas drilling programs for the past
several
years, and have represented that we have determined that none of those
programs
has resulted in a tax shelter ratio greater than two to one. Further, we
have
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 believe that no person could
reasonably
infer from representations made, or to be made, in connection with the
offering
of units that sums as of dates will exceed two
times the
partners' cash investments as of dates.
10. We have 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. We have
represented
that we do not believe that any market will ever exist for the sale of
units and that we 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 from its operations.
12. We 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
limited partnership agreement and to take any and all actions under the
agreement
in connection with the transactions contemplated by the agreement.
You should be aware that, unlike a ruling from the Service, an opinion
of
counsel represents only 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 . You should consult your own tax advisor to determine
the
effect of the tax issues discussed in this section and in Appendix D on your
individual tax situation.
General Tax Effects of Partnership Structure
Each partnership will be formed as a limited partnership
the limited 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 in
this
section 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
limited partnership agreement and applicable state law and representations
made
by us. 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, we can give no assurance 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 items in accordance
with
the partnership agreement and is required to take items into
account in
determining the partner's income. Each partner includes 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
designated "PDC 2001- Limited Partnership," in 2002 for
partnerships
designated "PDC 2002-Limited Partnership," and in 2003 for
partnerships
designated "PDC 2003- 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 . 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 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 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 us from 1984 through
2000
(see "Prior Activities - Tax Deductions and Tax Credits of Participants in
Previous Partnerships," above), intangible drilling costs have ranged from
approximately 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
labeled as IDC as a cost which must be capitalized. To the extent not
deductible, amounts will be included in the partnership's
basis
in mineral property.
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 (see "Alternative Minimum Tax").
In order for the IDC to qualify for deduction in 2001, 2002 and 2003,
respectively, the wells for partnerships designated "PDC 2001-
Limited
Partnership," "PDC 2002- Limited Partnership," and "PDC 2003- Limited
Partnership," respectively, must be spudded by March 30, 2002, 2003, and
2004,
respectively. requirements must also be met. Although PDC will
attempt
to satisfy each requirement of the Service and judicial authority for
deductibility of IDC in 2001, 2002, and 2003, respectively, for
partnerships designated "PDC 2001- Limited Partnership," "PDC 2002-
Limited Partnership," and "PDC 2003- Limited Partnership," respectively, we
can
give no assurance that the Service will not successfully contend that the
IDC of
a well which is not completed until 2001, 2002, or 2003, respectively, for
partnerships designated "PDC 2001- Limited Partnership," "PDC 2002-
Limited Partnership," or "PDC 2003- Limited Partnership," respectively, are
not
deductible in whole or in part until 2002, 2003, or 2004, respectively, for
partnerships designated "PDC 2001- Limited Partnership," "PDC 2002-
Limited Partnership," or "PDC 2003- Limited Partnership," respectively.
Further,
to the extent drilling of the partnership's wells does not commence
by
March 30, 2002, 2003, or 2004, respectively, for partnerships
designated
"PDC 2001- Limited Partnership," "PDC 2002- Limited Partnership," or "PDC
2003-
Limited Partnership," respectively, the deductibility of all or a portion
of the
IDC may be deferred. Notwithstanding the foregoing, we can give no
assurance
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
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 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. For 2000, the deduction is 19% (15% for wells producing more than
90 Mcf
per day or 15 barrels of oil per day) of gross income not to exceed 65% of
the
taxpayer's taxable income or 100% of the net income on a property by
property
basis. The latter limitation does not apply to "stripper wells" for tax
years
1998 to 2001. After 2000, the depletion rate may change but will be within
the
range of 15% to 25%.
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 depletion methods.
Percentage
depletion is generally available only with respect to the domestic oil and
gas
production of "independent producers." In order to qualify as an
independent producer, the taxpayer, either directly or through
related
parties, may not be involved in the refining of more than 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 the case of partnerships, the depletion allowance must be computed
separately
by each partner and not by the partnership. For properties placed in
service
after 1986, depletion deductions, to the extent they reduce basis in an oil
and
gas property, are subject to recapture under section 1254.
Cost depletion for any year is determined by multiplying the number
of
units (e.g., barrels of oil or Mcf of gas) sold during the year by a
fraction,
the numerator of which is the cost or other basis of the mineral interest
and the
denominator of which is total reserves available at the beginning of the
period.
In no event can the cost depletion exceed the adjusted basis of the property
to
which it relates.
Percentage depletion is a statutory allowance 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 the net income on a property by property
basis,
and further limited to 65% of a taxpayer's taxable income. 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
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% nor
more
than 25%. Code Section 613A(c)(6)(C). 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
share of the adjusted basis for any depletion taken on
property, and use adjusted basis each year in the computation
of his
cost depletion or in the computation of his gain or loss on the disposition
of
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. 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 . 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. You will not be able to claim depreciation deductions because all
tangible costs have been allocated to us.
Interest Deductions
In the 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 us, some investors 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
loans, counsel is unable to express an opinion with respect to the
deductibility of any interest paid or incurred on loans.
Transaction Fees
- Partnership expenditures classified as
organizational
expenses, and start-up expenses may be amortized over periods ranging from
60
months to the life of the property.
- No deduction is permitted for syndication expenses,
including sales commissions for the purchase of Units.
The partnership may classify a portion of the fees to be paid
to
third parties and to us 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 these 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 assets.
No deduction is allowable with respect to "start-up expenditures,"
although
expenditures may be capitalized and amortized over a period of not
less
than 60 months.
The partnership intends to make payments to us, 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
decrease the net loss, or increase the net income among all
partners.
If the Service were to successfully challenge our allocations, a
partner's
taxable income could be increased, resulting in increased taxes and
in
liability for interest and penalties.
Basis and At Risk Limitations
- Partners contributing cash from 'personal funds'
will not
be limited, to the extent of cash contributed, in their deductibility of
partnership losses by the 'at risk' basis rules or the limitations
related
to a partner's basis in his 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 activity at the close of the taxable year. In general,
a
partner is "at risk" to the extent of the amount of cash and the
adjusted
basis of other property contributed to the partnership Any
loss
disallowed by the "at risk" limitation shall be treated as a deduction
allocable
to the activity in the first succeeding taxable year.
The Code provides that a taxpayer must recognize taxable income to the
extent that his "at risk" amount is reduced below zero. This recaptured
income
is limited to the sum of the loss deductions previously allowed to the
taxpayer,
less any amounts previously recaptured. A taxpayer may be allowed a
deduction
for the recaptured amounts included in his taxable income if and when he
increases his amount "at risk" in a subsequent taxable year.
The partners will purchase units by tendering cash to
the
partnership . To the extent the cash contributed constitutes the
"personal
funds" of the partners the partners should be considered at
risk
with respect to those amounts. To the extent the cash contributed
constitutes
"personal funds," in the opinion of counsel, neither the at risk rules nor
the
adjusted basis rules will limit the deductibility of losses generated from
the
partnership . In no event, however, may a partner utilize his
distributive
share of partnership loss where 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 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 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 year.
Individuals and personal service corporations will be entitled to
only to the extent of their passive income whereas closely held C
corporations (other than personal service corporations) can offset
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. 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 will not be considered as
investments in passive activities for federal tax purposes.
- Additional 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.
A limited partner's interest in the partnership will be
considered a passive activity and losses generated while limited
partnership interest is held will be limited by the passive activity
provisions.
In general, an additional general partner's interest in the
partnership will not be considered a passive activity, and losses
generated while general partner interest is held will not be
limited by
the passive activity provisions. However, if an additional general
partner interest is converted to a limited partner interest prior to the
spudding date, but after the end of the taxable year in which IDC was
incurred,
IDC will be subject to the passive activity rules. In addition, that
portion of
partnership income for prior taxable year attributable to
IDC
treated as passive loss will be considered passive. The "spudding date" is
the
date that drilling commences.
If an additional general partner converts his interest to a
limited partner interest the terms of the limited
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.
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 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 , 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 the disallowed 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 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 partner
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 to the partnership . This constructive
termination could have adverse income tax consequences,
described
in the opinion in Appendix D. For a discussion of the conversion feature
of the
, see "Terms of the Offering - Conversion of Units by Additional
General
Partners."
Alternative Minimum Tax
- Due to the potentially significant impact of a
purchase
of units on an investor's tax liability, investors should
discuss
the implications of an investment in the partnership on their regular
and
AMT liabilities with their tax advisors prior to acquiring units .
Tax benefits associated with oil and gas exploration activities
similar to
that of the 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 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
- 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.
the recapture of IDCs and depletion ordinary income If
the
the amou gain exceeds the amount of the recaptured ,
the
investor will recognize ordinary income to the extent of the be
required
to recognize ordinary income . 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
transaction in accordance with Regulations and must attach a statement to
his tax
return reflecting 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 in this prospectus. Any assignor of a
unit should advise his assignee to consult his own tax advisor
regarding
the tax consequences of assignment.
Partnership Distributions
Under the Code, any increase in a partner's share of partnership
liabilities, or any increase in 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
the
partner's individual liabilities by reason of the partnership's assumption
of
the 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 the 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
limited partnership agreement prohibits distributions to any investor
partner
to the extent the 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 limited partnership agreement.
The Service could contend that the allocations contained in the
limited
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
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 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 the activity for three or more of the five
consecutive
taxable years ending with the taxable year in question. At the taxpayer's
election, the 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 , 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 beyond any tax benefits derived from those activities or
risk
losing those tax benefits.
Administrative Matters
Returns and Audits. While no federal income tax is required to be
paid by
an organization classified as a partnership for federal income tax purposes,
a
partnership must file federal income tax information returns, which are
subject
to audit by the Service. Any audit may lead to adjustments, in
which
event you may be required to file amended personal federal income tax
returns.
Any audit may also lead to an audit of your 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
the administrative proceedings and decisions , 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 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 limited
partnership agreement provides for waiver of of these rights by the
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 us, all partners of that partnership
may
be deemed parties to the litigation and bound by the result reached
.
Consistency Requirements. You must generally treat partnership
items on your federal income tax returns consistently with the treatment of
the items on the partnership information return unless you
file a
statement with the Service identifying the inconsistency or otherwise
satisfy the
requirements for waiver of the consistency requirement. Failure to satisfy
this
requirement will result in an adjustment to conform your treatment of the
item
with the treatment of the item on the partnership return.
Intentional or
negligent disregard of the consistency requirement may subject you 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 the 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 conditions are met.
In the case of understatements attributable to "tax shelter" items,
the
substantial understatement penalty may be avoided only if the taxpayer
establishes that, in addition to having substantial authority for his
position,
he reasonably believed the treatment claimed was more likely than not the
proper
treatment of the item. A "tax shelter" item is one that arises from a
partnership (or other form of investment) the principal purpose of which is
the
avoidance or evasion of federal income tax. Under the GATT legislation, a
corporation is generally held to a higher standard to avoid the substantial
understatement penalty.
Based on the definition of a "tax shelter" in the Regulations,
performance
of previous partnerships sponsored by us since 1984, and the planned
activities
of the Program, we have represented that the Partnerships will not qualify
as
"Tax Shelters" under the Code, and will not register them as . 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 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
these 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 .
State and Local Taxes
The opinions expressed are limited to issues of federal income
tax
law and do not address issues of state or local law. We urge you to consult
your
tax advisors regarding the impact of state and local laws on your investment
in
the partnership .
Individual Tax Advice Should Be Sought
We have presented only a summary of the material tax considerations
that
may affect your 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 . You should review the tax consequences
with
your tax advisor.
SUMMARY OF LIMITED PARTNERSHIP AGREEMENT
The limited partnership agreement in the form attached to this
prospectus
as Appendix A will govern your rights and obligations. You, together with
your
personal advisers, should carefully study the limited partnership agreement
in
its entirety before submitting a subscription. The following statements
concerning the limited partnership agreement are merely a summary of all the
material terms of the limited partnership agreement, but do not purport to
be
complete and in no way amend or modify the limited 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 limited 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 limited partnership agreement to others,
including entities related to it. Section 5.02.
Liabilities of General Partners, Including Additional General Partners
General partners, including additional general partners ,
will
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.
We, as operator, maintain general liability insurance. In addition,
we
have 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 partner , by execution of the limited
partners, grant to the Managing General Partner the exclusive authority
to
manage the partnership business in its sole discretion and to
bind
the partnership and all partners in its conduct of the
partnership business. The additional general partner may not
participate in the management of the partnership business; and the
limited
partnership agreement prohibits the additional general partner 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 acts in contravention of the terms of the
limited partnership agreement, losses caused by his or her actions will be
borne
by the may be liable to other partners for all damages
resulting
from his or her breach of the limited partnership agreement. Section 7.01.
Additional who choose to assign their units in the future
may do
so only as provided in the limited partnership agreement and liability of
partners who have assigned their units may continue after
the 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
the
return (or six years in the event the return is in violation of the
limited partnership 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 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 limited 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
limited partnership agreement to the contrary, no partner will
receive any
distribution to the extent the 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.
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
limited 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 the 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:
- The sale of all or substantially all of the assets of the
partnership ;
- Removal of the Managing General Partner and election of a new
managing
general partner;
- Dissolution of the partnership ;
- Any non-ministerial amendment to the limited partnership agreement;
- Cancellation of contracts for services with the Managing General
Partner
or affiliates; and
- 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 .
Additionally, the partnership is not permitted to participate
in a
transaction unless the 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 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 Act. 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 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, 2051 unless earlier dissolved upon the occurrence of any of the
following:
-the written consent of the investor partners owning a
majority of
the then outstanding units ;
-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 the limited partnership agreement
or
the remaining managing general partner, if any, continues the
partnership's business;
-the sale, forfeiture, or abandonment of all or substantially all of
the
partnership's property; or
-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 partner 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 limited partners, then the
foregoing
indemnification by the Managing General Partner will be unenforceable as to
will be liable to all other partners for damages and obligations
resulting the. 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 the 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
the course of conduct was in the best interest of the Partnership and
the 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 and state securities laws
unless
there has been a successful adjudication on the merits of each count
involving securities law violations; or
the claims have been dismissed with prejudice on their merits by a
court
of competent jurisdiction; or
a court of competent jurisdiction approves a settlement of the
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 which are
specifically
set forth in the prospectus and in which plaintiffs claim they were
offered or sold partnership.
In any claim for indemnification for 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.
The partnership will not incur the cost of the portion of any
insurance which insures any party against any liability as to which
the
party is prohibited from being indemnified. Section 6.04.
Reports to Partners
The Managing General Partner will furnish to the investor partners
of each partnership 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 the statements with information provided to the investor
partners
for 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
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, 2001 with respect to partnerships designated "PDC
2001-
Limited Partnership," December 31, 2002 with respect to partnerships
designated "PDC 2002- Limited Partnership," and December 31, 2003, with
respect
to partnerships designated "PDC 2003- 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 , 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 income tax returns and any required
state
income tax returns by March 15 of each calendar year. Investor
partners
will also receive in the 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 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 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 limited partnership agreement are summarized
in
this 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
- Your sale of units is limited; no public market exists
or will
develop for the units ; you may not be able to sell your units
at
the price or when you want.
- Purchasers of units from you must satisfy the suitability
requirements of this offering and as imposed by law.
No public market exists or will develop for the units . You
should
consider an investment in the partnerships an illiquid investment.
You
may not be able to sell your units when and if you want to do so and
at
the price you believe to be fair. In addition, as a basis of counsel's
opinion
that the partnerships will not be treated as "publicly traded
partnerships," we have represented that the units will not be traded
on
an established securities market or the substantial equivalent thereof.
While units of the partnership are transferable,
assignability of the units is limited, requiring among other things
our
consent. Section 7.03. Transfers of fractional units are
prohibited,
unless you own a fractional unit , in which case your entire
fractional
interest must be transferred. You 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 you make an assignment 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 we consent to 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, 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, we, after having determined that the purported transferee
satisfies the
suitability standards of an additional general partner and other
conditions established by the , will promptly notify the purported
transferee of the partnership's consent to the transfer and will
include
with the notice a copy of the limited partnership agreement, together with
a
signature page. In the notification, we will advise the transferee
that
he or she will have the same rights and responsibilities, including
unlimited
liability, as every other additional general partner and that he or
she
will not become a partner of record until he or she returns the
executed
signature page to the partnership need not recognize any assignment
until
the instrument of assignment has been delivered to us. The assignee of
the interests has rights of ownership but may become a
substituted
investor partner and thus be entitled to all of the rights of an
additional general partner only upon meeting conditions,
including
obtaining our consent to the substitution,
paying all costs and expenses incurred in connection with the
substitution,
making representations to us and
executing appropriate documents to evidence its agreement to be bound
by
all of the terms and provisions of the applicable limited partnership
agreement.
Conversion of Units by the Managing General Partner and by Additional
General Partners. Upon completion of drilling of a particular
partnership , we will convert all units of general partnership
interest of that partnership into units of limited partnership
interest of that partnership . See "Terms of the Offering -
Conversion of Units by the Managing General Partner and by Additional
General
Partners
Unit Repurchase Program. Beginning with the third anniversary of the
date
of the first cash distribution of the partnership , you may tender
your
units to us for repurchase, subject to 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
allow the offering to close and a partnership to be funded.
We are offering for sale units of preformation limited and general
partnership interest through PDC Securities Incorporated, the , our
affiliate, 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 (including IRAs and other tax-exempt plans) 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 2001-D
Limited
Partnership, PDC 2002-D Limited Partnership, and PDC 2003-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 2001-D Limited
Partnership, PDC 2002-D Limited Partnership, and PDC 2003-D Limited
Partnership)
that can be raised with respect to any partnership .
The , 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 750 units ($157,500
for
the sale of the minimum number of 75 units for a partnership ;
$262,500 for the sale of the minimum number of 125 units and
$2,625,000
for the sale of the maximum number of units for each of PDC 2001-D
Limited
Partnership, PDC 2002-D Limited Partnership and PDC 2003-D Limited
Partnership).
The may reallow these commissions, expenses and fees, in whole or
in
part, to NASD-licensed broker-dealers for sale of the units The
will not reallow the wholesaling fees. In no event will the total
compensation paid to NASD members exceed 10 1/2% of subscriptions (comprised
of
8% in sales commissions, .5% in wholesaling fees, and 1.5% in marketing
support
fees and other compensation and .5% of subscriptions for reimbursement of
bona
fide due diligence expenses). Any commissions and other
remuneration
will be paid in cash solely on the amount of initial subscriptions and only
as
permitted under 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, we, prior to the
time
that we have received the minimum required subscriptions in cleared funds
from
subscribers that are 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 our own funds the sales
commissions
and due diligence expenses which would otherwise be payable in connection
with
the subscriptions prior to the close and funding of the
partnership
the minimum sale of 75 units (125 units with respect to
each
of PDC 2001-D Limited Partnership, PDC 2002-D Limited Partnership and PDC
2003-D
Limited Partnership) has not occurred as of the time as the
particular
offering terminates or we determine not to organize and fund the
partnership for any reason, broker-dealers which have
received
commissions and due diligence expenses in advance from us with respect to
the
sale of units in that partnership are required by the
soliciting-dealers agreements to return the commissions and due
diligence
expenses to us promptly.
No sales commissions will be paid on sales of units to
officers,
directors, employees, or registered representatives of a , in its
discretion, has elected to waive the sales commissions. Any
units
so purchased will be held for investment and not for resale.
We, the , and soliciting dealers have agreed to indemnify one
another against civil liabilities, including liability under the
Securities Act of 1933 . Members of the selling group may be deemed
to be
"underwriters" as defined under the Securities Act , and their
commissions
and other payments may be deemed to be underwriting compensation.
The 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.
We and our 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 us and/or our affiliates may have the effect of
allowing the offering to be subscribed to the minimum, an express
condition of the offering, and thus allow the offering to close. We and/or
our
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 us and affiliates are permitted to be
applied to satisfying the minimum requirement. Any units purchased
by us
and/or our 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 aspects of the
,
namely, a highlight information piece which will constitute the
prospectus summary ("Program Summary" in bullet format), an introduction to
the
("Flip Chart/Slide Presentation"), and prospect letters
("Broker-Dealer
Guide"). The may also utilize a 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. 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 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., Washington, D.C. 20006.
EXPERTS
The Partnership reserve and future net revenues information 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 and in the
have been included and in the in reliance upon the
reports
of KPMG LLP, independent auditors, appearing elsewhere , and upon
the
authority of said firm as experts in accounting and auditing.
ADDITIONAL INFORMATION
A on Form S-1 (Reg. No. 333- with respect to the
units offered has been filed on behalf of the
partnerships
with the Securities and Exchange Commission, Washington, D.C. 20549, under
the
Securities Act of 1933 . This prospectus does not contain all of the
information set forth in the portions of which have been omitted
the rules and regulations of the Securities and Exchange Commission.
Reference is made to the, including exhibits, for further
information.
You may read and copy any materials we file with the SEC at the SEC's Public
Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. You may
obtain
information on the operation of the Public Reference Room by calling the SEC
at
1-800-SEC-0330. This , as well as all exhibits and amendments
,
have been filed and will be filed electronically with the Commission through
the
Electronic Data Gathering, Analysis, and Retrieval ("EDGAR") system. the
and all exhibits and amendments thereto are publicly available through
the
Commission's Web site (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 , and we qualify each statement in this
prospectus in all respects by this reference. You may obtain copies of any
materials filed as a part of the from the Securities and Exchange
Commission by payment of the requisite fees or you may examine 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
is
correct as of any time subsequent to the date .
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 the 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 the
specified
person; (c) any person directly or indirectly controlling, controlled by,
or
under common control with the specified person; (d) any officer,
director,
trustee or partner of the specified person; and (e) if the
specified person is an officer, director, trustee or partner, any person for
which the person acts in any 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 Section 3.01 of the limited
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 the to the capital of the partnership Section
2.02
of the limited partnership agreement and, with respect to the Managing
General
Partner and , the total investment, including the original
investment,
assessments and amounts reinvested, to the capital of the partnership
Section 2.01 of the limited 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 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
the 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 the 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 the property to the date of its transfer to the
buyer,
interest and points actually incurred on funds used to acquire or maintain
the property, and the 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 the 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 the 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, our affiliate.
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
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 the services are
provided written contracts and in compliance with Section 5.07(e)
of the
limited 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 the owner of a leasehold or working interest
agrees to assign an interest in specific acreage to the assignees,
retaining an interest such as an overriding royalty interest, an oil and gas
payment, offset acreage or other type of interest, subject to the drilling
of one
or more specific wells or other performance as a condition of the
assignment.
Horizon: A zone of a particular formation; that part of a formation of
sufficient porosity and permeability to form a petroleum reservoir.
IDC: Intangible drilling and development costs.
Independent Expert: A person with no material relationship to the Managing
General Partner who is qualified and who is in the business of rendering
opinions
regarding the value of oil and gas properties based upon the evaluation of
all
pertinent economic, financial, geologic and engineering information
available to
the Managing General Partner.
Initial Limited Partner: Steven R. Williams or any successor to his
interest.
Investor Partner: Any investor participating in the partnership as
an
Additional General Partner or a limited partner , but excluding the
Managing General Partner and .
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: undeveloped oil and gas
leases;
oil and gas mineral rights; licenses; ( concessions;
contracts; fee rights; or 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,
transferees or assignees who become limited partners whose
interests
are converted to limited partnership interests the provisions of
the
limited partnership agreement.
Limited 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.
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 income tax laws.
Management Fee: The fee to which the Managing General Partner is entitled
Section 6.06 of the limited 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 60E 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, 2001 with respect to
partnerships
designated "PDC 2001- Limited Partnership," December 31, 2002 with respect
to
partnerships designated "PDC 2002- Limited Partnership," and December
31,
2003 with respect to partnerships designated "PDC 2003- Limited
Partnership" or the 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 the 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 the
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
the operations.
Organization and Offering Costs: All costs of organizing and selling the
offering including, but not limited to, total underwriting and brokerage
discounts and commissions (including fees of the underwriters' attorneys),
expenses for printing, engraving, mailing, salaries of employees while
engaged
in sales activity, charges of transfer agents, registrars, trustees, escrow
holders, depositaries, engineers and other experts, expenses of
qualification of
the sale of the securities under federal and state law, including taxes and
fees,
accountants' and attorneys' fees and other frontend fees.
Overriding Royalty Interest: An interest in the oil and gas produced
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 .
Partners: The Managing General Partner, the additional general
partner
other than the Managing General Partner, and the limited partners .
Reference to a " shall mean any one of the partners .
Partnership or Partnerships: One or all of the limited partnerships to be
formed
in the PDC 2003 Drilling Program comprised of a series of up to twelve
limited
partnerships to be designated as the PDC 2001-A Limited Partnership, the PDC
2001-B Limited Partnership, the PDC 2001-C Limited Partnership, PDC 2001-D
Limited Partnership, PDC 2002-A Limited Partnership, PDC 2002-B Limited
Partnership, PDC 2002-C Limited Partnership, PDC 2002-D Limited Partnership,
PDC
2003-A Limited Partnership, PDC 2003-B Limited Partnership, PDC 2003-C
Limited
Partnership, and PDC 2003-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
2003 Drilling Program or sometimes as the .
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 income tax laws.
Program: One or more limited partnerships formed, or to be formed, for the
primary purpose of exploring for oil or gas. , PDC 2003 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 limited partnership agreement is a part,
which
the units are being offered and sold.
Proved Developed Oil and Gas Reserves. Proved developed oil and gas
reserves are
reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods. Additional oil and gas expected
to be
obtained through the application of fluid injection or other improved
recovery
techniques for supplementing the natural forces and mechanisms of primary
recovery should be included as "proved developed reserves" only after
testing by
a pilot project or after the operation of an installed program has confirmed
through production response that increased recovery will be achieved.
Proved Oil and Gas Reserves: Proved oil and gas reserves are the estimated
quantities of crude oil, natural gas, and natural gas liquids which
geological
and engineering data demonstrate with reasonable certainty to be recoverable
in
future years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is made.
Prices
include consideration of changes in existing prices provided only by
contractual
arrangements, but not on escalations based upon future conditions.
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.
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.
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 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 the 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. the term does not
include:
(a) a transaction involving securities of the partnership
that
have been listed for at least 12 months on a national exchange or traded
through
the National Association of Securities Dealers Automated Quotation National
Market System; or
(b)a transaction involving the conversion to corporate, trust or
association form of only the partnership if, as a consequence of the
transaction, there will be no significant adverse change in any of the
following:
(1)voting rights;
(2)the term of existence of the partnership ;
(3)sponsor compensation; or
(4)the partnership's investment objectives.
Roll_Up Entity: A partnership, trust, corporation or other entity that
would be
created or survive after the successful completion of a proposed roll-up
transaction.
Royalty: A fractional undivided interest in the production of oil and gas
wells,
or the proceeds therefrom to be received free and clear of all costs of
development, operations or maintenance. Royalties may be reserved by
landowners
upon the creation of an oil and gas lease ("landowner's royalty") or
subsequently
carved out of a working interest ("overriding royalty").
Securities Act: Securities Act of 1933, as amended.
Sponsor: Any person directly or indirectly instrumental in organizing,
wholly
or in part, a program or any person who will manage or is entitled to manage
or
participate in the management or control of a program. "Sponsor" includes
the
managing and controlling general partner(s) and any other person who
actually
controls or selects the person who controls 25% or more of the exploratory,
developmental or producing activities of the partnership , or any
segment
thereof, even if that person has not entered into a contract at the time of
formation of the partnership . "Sponsor" does not include wholly
independent third parties such as attorneys, accountants, and underwriters
whose
only compensation is for professional services rendered in connection with
the
offering of units. Whenever the context of these guidelines so requires,
the
term "sponsor" shall be deemed to include its affiliates.
Spudding Date: The date that drilling commences.
Subscriptions: The subscription agreement(s) or the amount indicated on the
subscriptions agreements that the additional general partner and the
limited partners have agreed to pay to a partnership .
Tangible Costs: Those costs which are generally accepted as capital
expenditures
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 a representative of the who helps
introduce and explain the to registered representatives with firms
executing a selling agreement with the for the .
Working Interest: An interest in an oil and gas leasehold which is subject
to
some portion of the costs of development, operation, or maintenance.
No dealer, salesman or other person has been authorized to give any
information or make any representations other than those contained in this
prospectus in connection with this offering. You should rely only upon the
information contained in this prospectus. We have not authorized anyone to
provide you with different information.
If it is against the law in any state to make an offer to sell the
units (or to solicit an offer from someone to buy the units ,
then
this prospectus does not apply to any person in that state, and no offer or
solicitation is made by this prospectus to any person and we do not
authorize the use of this prospectus to any person in that state.
Throughout this offering, all dealers effecting transactions in the
registered securities, whether or not participating in this distribution,
are
required to deliver a prospectus. This is in addition to the obligation of
dealers to deliver a prospectus when acting as underwriters and with respect
to
their unsold allotments or subscriptions.
7,500 Preformation Units of
General and Limited
Partnership Interest
[PDC logo]
PDC 2003
DRILLING PROGRAM
$150,000,000
Aggregate Subscriptions
PROSPECTUS
Dated , 2001
PDC SECURITIES INCORPORATED
103 East Main Street
Bridgeport, West Virginia 26330
800/624-3821
Dealer Manager
A Member of the National Association of Securities Dealers, Inc. and
Securities
Investor Protection Corporation
PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets
September 30, 2000 and December 31, 1999
<TABLE>
<C>
<C>
<C>
ASSETS
2000 1999
(Unaudited)
Current assets:
Cash and cash equivalents $ 13,736,800 $ 29,059,200
Accounts and notes receivable 18,885,800 10,263,200
Inventories 838,600 577,600
Prepaid expenses 7,232,200 2,360,100
Total current assets 40,693,400 42,260,100
Properties and equipment 133,954,000 118,349,100
Less accumulated depreciation,
depletion and amortization 36,188,800 31,207,300
97,765,200 87,141,800
Other assets 3,083,500 2,681,700
$141,542,100 $132,083,600
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses $ 21,564,000 $
17,599,000
Advances for future drilling contracts 11,191,700 25,137,400
Funds held for future distribution 2,794,200 2,027,600
Total current liabilities 35,549,900 44,764,000
Long-term debt, excluding current maturities 18,475,000 9,300,000
Other liabilities 3,907,200 3,160,600
Deferred income taxes 4,689,600 4,134,100
Commitments and contingencies
Stockholders' equity:
Common stock 162,400 157,400
Additional paid-in capital 32,931,400 32,071,000
Retained earnings 45,826,600 38,496,500
Total stockholders' equity 78,920,400 70,724,900
$141,542,100 $132,083,600
</TABLE>
An investor in PDC 2003 Drilling Program does not thereby acquire any
interest
in the assets of Petroleum Development Corporation.
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 September 30, 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 September 30, 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 September 30, 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 2003 Drilling Program does not thereby acquire any
interest
in the assets of Petroleum Development Ccorporation.
Petroleum Development Corporation and Subsidiaries
Consolidated Balance Sheets
December 31, 1999 and 1998
(With Independent Auditor's Report Thereon)
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
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 2003 Drilling Program does not thereby acquire any
interest in the assets of Petroleum Development Corporation
(Continued)
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
See accompanying notes to consolidated balance sheets.
</TABLE>
An investor in PDC 2003 Drilling Pprogram does not thereby acquire any
interest in the assets of Petroleum Development Corporation
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)
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)
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)
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)
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. The Company is in compliance with all covenants of the credit
agreement.
(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)
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>
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)
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)
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)
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:
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
(Continued)
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:
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
(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)
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)
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>
APPENDIX A
FORM OF
LIMITED PARTNERSHIP AGREEMENT
OF
PDC 2001-___ LIMITED PARTNERSHIP
[PDC 2002-___ LIMITED PARTNERSHIP]
[PDC 2003-___ LIMITED PARTNERSHIP]
TABLE OF CONTENTS
Page
ARTICLE I: The Partnership 1
1.01 Organization 1
1.02 Partnership Name 1
1.03 Character of Business 1
1.04 Principal Place of Business 1
1.05 Term of Partnership 2
1.06 Filings 2
1.07 Independent Activities 2
1.08 Definitions 3
ARTICLE II: Capitalization 12
2.01 Capital Contributions of the Managing General
Partner and Initial Limited Partner 12
2.02 Capital Contributions of the Investor
Partners 13
2.03 Additional Contributions 14
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 23
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 25
ARTICLE V: Activities 25
5.01 Management 25
5.02 Conduct of Operations 25
5.03 Acquisition and Sale of Leases 27
5.04 Title to Leases 28
5.05 Farmouts 28
5.06 Release, Abandonment, and Sale or Exchange
of Properties 29
5.07 Certain Transactions 29
ARTICLE VI: Managing General Partner 34
6.01 Managing General Partner 34
6.02 Authority of Managing General Partner 35
6.03 Certain Restrictions on Managing General
Partner's Power and Authority 36
6.04 Indemnification of Managing General
Partner 38
6.05 Withdrawal 39
6.06 Management Fee 39
6.07 Tax Matters and Financial Reporting
Partner 39
ARTICLE VII: Investor Partners 40
7.01 Management 40
7.02 Indemnification of Additional
General Partners 40
7.03 Assignment of Units 41
7.04 Prohibited Transfers 43
7.05 Withdrawal by Investor Partners 43
7.06 Removal of Managing General Partner 43
7.07 Calling of Meetings 44
7.08 Additional Voting Rights 44
7.09 Voting by Proxy 45
7.10 Conversion of Additional General Partner
Interests into Limited Partner Interests 45
7.11 Unit Repurchase Program 46
7.12 Liability of Partners 47
ARTICLE VIII: Books and Records 47
8.01 Books and Records 47
8.02 Reports 48
8.03 Bank Accounts 50
8.04 Federal Income Tax Elections 50
ARTICLE IX: Dissolution; Winding-up 51
9.01 Dissolution 51
9.02 Liquidation 52
9.03 Winding-up 52
ARTICLE X: Power of Attorney 53
10.01 Managing General Partner as Attorney-in-Fact 53
10.02 Nature of Special Power 54
ARTICLE XI: Miscellaneous Provisions 54
11.01 Liability of Parties 54
11.02 Notices 54
11.03 Paragraph Headings 55
11.04 Severability 55
11.05 Sole Agreement 55
11.06 Applicable Law 55
11.07 Execution in Counterparts 55
11.08 Waiver of Action for Partition 55
11.09 Amendments 55
11.10 Consent to Allocations and Distributions 56
11.11 Ratification 56
11.12 Substitution of Signature Pages 56
11.13 Incorporation by Reference 56
Signature Page. . . . . . . . . . 57
FORM OF
LIMITED PARTNERSHIP AGREEMENT
OF PDC 2001- LIMITED PARTNERSHIP,
[PDC 2002- LIMITED PARTNERSHIP,]
[PDC 2003- LIMITED PARTNERSHIP,]
A WEST VIRGINIA LIMITED PARTNERSHIP
This LIMITED PARTNERSHIP AGREEMENT (the "Agreement") is made as of
this ___
day of ___________, 2001, [2002; 2003] 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
2001-
Limited Partnership, [PDC 2002- Limited Partnership; PDC 2003- 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
2001-D Limited Partnership, PDC 2002-D Limited Partnership and PDC 2003-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.
1.06 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 47-9-1 through 47-9-63 thereof, as
amended
from time to time (or any corresponding provisions of succeeding law).
(b) "Additional General Partner" shall mean an Investor Partner who
purchases Units as an additional general partner, and such partner's
transferees
and assigns. "Additional General Partners" shall mean all such Investor
Partners. "Additional General Partner" shall not include, after a
conversion,
such Investor Partner who converts his interest into a Limited Partnership
interest pursuant to Section 7.10 herein.
(c) "Administrative Costs" shall mean all customary and routine
expenses
incurred by the Managing General Partner for the conduct of program
administration, including legal, finance, accounting, secretarial, travel,
office
rent, telephone, data processing and other items of a similar nature.
(d) "Affiliate" of a specified person shall mean (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 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. 1.704-1(b)(2)(ii)(g);
provided, however, that the adjustments pursuant to clauses (a) and (b)
above
shall be made only if the Managing General Partner reasonably determines
that
such adjustments are necessary or appropriate to reflect the relative
economic
interests of the Partners in the Partnership;
(3) The Gross Asset Value of any Partnership asset distributed to any
Partner
shall be the gross fair market value of such asset on the date of
distribution;
and
(4) The Gross Asset Values of Partnership assets shall be increased (or
decreased) to reflect any adjustments to the adjusted basis of such assets
pursuant to Code Section 734(b) or Code Section 743(b), but only to the
extent
that such adjustments are taken into account in determining Capital Accounts
pursuant to Treas. Reg. 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.
(dd) "Nonrecourse Deductions" shall have the meaning set forth in
Treas.
Reg. 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. 1.704-2(c).
(ee) "Nonrecourse Liability" shall have the meaning set forth in
Treas.
Reg. 1.704-2(b)(3) and 1.752-1(a)(2).
(ff) "Offering Termination Date" shall mean December 31, 2001 with
respect
to Partnerships designated "PDC 2001- Limited Partnership (December 31, 2002
with
respect to Partnerships designated "PDC 2002- Limited Partnership" and
December
31, 2003 with respect to Partnerships designated "PDC 2003- Limited
Partnership")
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. 1.704-2(i).
(ll) "Partner Nonrecourse Debt" shall have the meaning set forth in
Treas.
Reg. 1.704-2(b)(4).
(mm) "Partner Nonrecourse Deductions" shall have the meaning set
forth in
Treas. Reg. 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. 1.704-2(i)(3).
(nn) "Partners" shall mean the Managing General Partner, the Initial
Limited Partner, and the Investor Partners. "Partner" shall mean any one
of the
Partners. All references in this Agreement to a majority in interest or a
specified percentage of the Partners shall mean Partners holding more than
50%
or such specified percentage, respectively, of the outstanding Units then
held.
(oo) "Partnership" shall mean the partnership pursuant to this
Agreement
and the partnership continuing the business of this Partnership in the event
of
dissolution as herein provided.
(pp) "Partnership Minimum Gain" shall have the meaning set forth in
Treas.
Reg. 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 703(a) (for this purpose,
all
items of income, gain, loss, or deduction required to be stated separately
pursuant to Code 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
705(a)(2)(B) or treated as Code 705(a)(2)(B) expenditures pursuant to
Treas.
Reg. 1.704-1(b)(2)(iv)(i), and not otherwise taken into account in
computing
Profits or Losses pursuant to this Section 1.08(rr) shall be subtracted from
such
taxable income or loss;
(3) In the event the Gross Asset Value of any Partnership
asset is
adjusted pursuant to Section 1.08(r)(2) or Section 1.08(r)(3) hereof, the
amount
of such adjustment shall be taken into account as gain or loss from the
disposition of such asset for purposes of computing Profits or Losses.
(4) Gain or loss resulting from any disposition of Partnership
Property with respect to which gain or loss is recognized for federal income
tax
purposes shall be computed by reference to the Gross Asset Value of the
property
disposed of, notwithstanding that the adjusted tax basis of such property
differs
from its Gross Asset Value;
(5) In lieu of the depreciation, amortization, and other cost
recovery deductions taken into account in computing such taxable income or
loss,
there shall be taken into account Depreciation for such fiscal year or other
period, computed in accordance with Section 1.08(r) hereof; and
(6) Notwithstanding any other provisions of this Section
1.08(rr),
any items which are specially allocated pursuant to this Agreement shall not
be
taken into account in computing Profits or Losses.
(tt) "Prospect" shall mean a contiguous oil and gas leasehold estate,
or
lesser interest therein, upon which drilling operations may be conducted.
In
general, a Prospect is an area in which the Partnership owns or intends to
own
one or more oil and gas interests, which is geographically defined on the
basis
of geological data by the Managing General Partner of such Partnership and
which
is reasonably anticipated by the Managing General Partner to contain at
least one
reservoir. An area covering lands which are believed by the Managing
General
Partner to contain subsurface structural or stratigraphic conditions making
it
susceptible to the accumulations of hydrocarbons in commercially productive
quantities at one or more horizons. The area, which may be different for
different horizons, shall be designated by the Managing 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, and (B) the
immediately
adjoining portions not yet drilled, but which can be reasonably judged as
economically productive on the basis of available geological and engineering
data. In the absence of information on fluid contacts, the lowest known
structural occurrence of hydrocarbons controls the lower proved limit of the
reservoir.
(2) Reserves which can be produced economically through application
of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for the
engineering analysis on which the project or program was based.
(3) Estimates or proved reserves do not include the following: (A)
oil
that may become available from known reservoirs but is classified separately
as
"indicated additional reserves; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors;
(C)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids, that may
be
recovered from oil shales, coal, gilsonite and other such sources.
(xx) "Proved Undeveloped Reserves" shall mean the reserves that are
expected to be recovered from new wells on undrilled acreage, or from
existing
wells where a relatively major expenditure is required for recompletion.
Reserves on undrilled acreage shall be limited to those drilling units
offsetting
productive units that are reasonably certain of production when drilled.
Proved
reserves for other undrilled units can be claimed only where it can be
demonstrated with certainty that there is continuity of production from the
existing productive formation. Under no circumstances should estimates for
proved undeveloped reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual
tests
in the area and in the same reservoir.
(yy) "Reservoir" shall mean a separate structural or stratigraphic
trap
containing an accumulation of oil or gas.
(zz) "Roll-Up" shall mean a transaction involving the acquisition,
merger,
conversion, or consolidation, either directly or indirectly, of the
Partnership
and the issuance of securities of a roll-up entity. Such term does not
include:
(1) a transaction involving securities of the Partnership that
have
been listed for at least 12 months on a national exchange or traded through
the
National Association of Securities Dealers Automated Quotation National
Market
System; or
(2) a transaction involving the conversion to corporate, trust
or
association form of only the Partnership if, as a consequence of the
transaction,
there will be no significant adverse change in any of the following:
(i) voting rights;
(ii) the term of existence of the Partnership;
(iii) sponsor compensation; or
(iv) the Partnership's investment objectives.
(aaa) "Roll-Up Entity" shall mean a partnership, trust, corporation
or
other entity that would be created or survive after the successful
completion of
a proposed roll-up transaction.
(bbb) "Sponsor" shall mean any person directly or indirectly
instrumental
in organizing, wholly or in part, a program or any person who will manage
or is
entitled to manage or participate in the management or control of a program.
"Sponsor" includes the managing and controlling general partner(s) and any
other
person who actually controls or selects the person who controls 25% or more
of
the exploratory, developmental or producing activities of the Partnership,
or any
segment thereof, even if that person has not entered into a contract at the
time
of formation of the Partnership. "Sponsor" does not include wholly
independent
third parties such as attorneys, accountants, and underwriters whose only
compensation is for professional services rendered in connection with the
offering of units. Whenever the context of these guidelines so requires,
the
term "sponsor" shall be deemed to include its affiliates.
(ccc) "Subscription" shall mean the amount indicated on the
Subscription
Agreement that an Investor Partner has agreed to pay to the Partnership as
his
Capital Contribution.
(ddd) "Subscription Agreement" shall mean the Agreement, attached
to the
Prospectus as Appendix B, pursuant to which an Investor subscribes to Units
in
the Partnership.
(eee) "Substituted Investor Partner" shall mean any Person admitted
to the
Partnership as an Investor Partner pursuant to Section 7.03(c) hereof.
(fff) "Treas. Reg." or "Regulation" shall mean the income tax
regulations
promulgated under the Code, as such regulations may be amended from time to
time
(including corresponding provisions of succeeding regulations).
(ggg) "Unit" shall mean an undivided interest of the Investor
Partners in
the aggregate interest in the capital and profits of the Partnership. Each
Unit
represents Capital Contributions of $20,000 to the Partnership.
(hhh) "Working Interest" shall mean an interest in an oil and gas
leasehold which is subject to some portion of the costs of development,
operation, or maintenance.
ARTICLE II
Capitalization
2.01 Capital Contributions of the Managing General Partner and
Initial
Limited Partner.
(a) On or before the Offering Termination Date, the Managing General
Partner shall make a Capital Contribution in cash to the Partnership of an
amount
equal to not less than 21-3/4% of the aggregate Capital Contributions of the
Investor Partners. The Managing General Partner shall pay all Lease and
tangible
drilling costs as well as all Intangible Drilling Costs in excess of such
costs
paid by the Investor Partners with respect to the Partnership; to the extent
that
such costs are greater than the Managing General Partner's Capital
Contribution
set forth in the previous sentence, the Managing General Partner shall make
such
additional contributions in cash to the Partnership equal to such additional
Costs; in the event of such additional Capital Contribution, the Managing
General
Partner's share of profits and losses and distributions shall equal the
percentage arrived at by dividing the Managing General Partner's Capital
Contribution by the Capital Available for Investment of the Partnership,
except
that such percentage may be revised by Sections 3.02 and 4.02. In
consideration
of making such Capital Contribution, becoming a General Partner, subjecting
its
assets to the liabilities of the Partnership, and undertaking other
obligations
as herein set forth, the Managing General Partner shall receive the interest
in
the Partnership allocated in Article III hereof.
(b) The Initial Limited Partner shall contribute $100 in cash to the
capital of the Partnership. Upon the earlier of the conversion of an
Additional
General Partner's interest into a Limited Partner's interest or the
admission of
a Limited Partner to the Partnership, the Partnership shall redeem in full,
without interest or deduction, the Initial Limited Partner's Capital
Contribution, and the Initial Limited Partner shall cease to be a Partner.
2.02 Capital Contributions of the Investor Partners.
(a) Upon execution of this Agreement, each Investor Partner (whose
names
and addresses and number of Units to which Subscribed are set forth in
Exhibit
A) shall contribute to the capital of the Partnership the sum of $20,000 for
each
Unit purchased. The minimum subscription by an Investor Partner is
one-quarter
Unit ($5,000).
(b) The contributions of the Investor Partners pursuant to
subsection
2.02(a) hereof shall be in cash or by check subject to collection.
(c) Until the Offering Termination Date and until such subsequent
time
as the contributions of the Investor Partners are invested in accordance
with the
provisions of the Prospectus, all monies received from persons subscribing
as
Investor Partners (i) shall continue to be the property of the investor
making
such payment, (ii) shall be held in escrow for such investor in the manner
and
to the extent provided in the Prospectus, and (iii) shall not be commingled
with
the personal monies or become an asset of the Managing General Partner or
the
Partnership.
(d) Upon the original sale of Units by the Partnership, subscribers
shall
be admitted as Partners no later than 15 days after the release from the
escrow
account of the Capital Contributions to the Partnership, in accordance with
the
terms of the Prospectus; subscriptions shall be accepted or rejected by the
Partnership within 30 days of their receipt; if rejected, all subscription
monies
shall be returned to the subscriber forthwith.
(e) Except as provided in Section 4.03 hereof, any proceeds of the
offering of Units for sale pursuant to the Prospectus not used, committed
for
use, or reserved as operating capital in the Partnership's operations within
one
year after the closing of such offering shall be distributed pro rata to the
Investor Partners as a return of capital and the Managing General Partner
shall
reimburse such Investors for selling expenses, management fees, and offering
expenses allocable to the return of capital.
(f) Until proceeds from the public offering are invested in the
Partnership's operations, such proceeds may be temporarily invested in
income
producing short-term, highly liquid investments, where there is appropriate
safety of principal, such as U.S. Treasury Bills. Any such income shall be
allocated pro rata to the Investor Partners providing such capital
contributions.
2.03 Additional Contributions. Except as otherwise provided in this
Agreement, no Investor Partner shall be required or obligated (a) to
contribute
any capital to the Partnership other than as provided in Section 2.02
hereof, or
(b) to lend any funds to the Partnership. No interest shall be paid on any
capital contributed to the Partnership pursuant to this Article II and,
except
as otherwise provided herein, no Partner, other than the Initial Limited
Partner
as authorized herein, may withdraw his Capital Contribution. The Units are
nonassessable; however, General Partners are liable, in addition to their
Capital
Contributions, for Partnership obligations and liabilities represented by
their
ownership of interests as general partners, in accordance with West Virginia
law.
ARTICLE III
Capital Accounts and Allocations
3.01 Capital Accounts.
(a) General. A separate Capital Account shall be established and
maintained for each Partner on the books and records of the Partnership.
Capital
Accounts shall be maintained in accordance with Treas. Reg. 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.
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. 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. 1.704-1(b)(2)(iv)(c)), but not by increases
in his
share of Partnership liabilities within the meaning of Code 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 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. 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. 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 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 752); (iv) allocations to him of expenditures of
the
Partnership not deductible in computing Partnership taxable income and not
properly chargeable to Capital Account (as described in Code
705(a)(2)(B)),
and (v) allocations to him of Partnership Losses (or item thereof),
including
loss and deduction described in Treas. Reg. 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.
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.
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
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:
(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. 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.
1.704-2(g)(1) and 1.704-2(i)(5). Further, such Capital Accounts shall
otherwise
meet the requirements of Treas. Reg. 1.704-1(b)(2)(ii)(d).
(ii) Reallocations. Any loss or deduction of the Partnership, the
allocation of which to any Partner is prohibited by this Section 3.02(b),
shall
be reallocated to those Partners not having a deficit in their Capital
Accounts
(as adjusted in Section 3.02(b)(i)) in the proportion that the positive
balance
of each such Partner's adjusted Capital Account bears to the aggregate
balance
of all such Partners' adjusted Capital Accounts, with any remaining losses
or
deductions being allocated to the Managing General Partner.
(iii) Qualified Income Offset. In the event any Investor
Partner
unexpectedly receives any adjustments, allocations, or distributions
described
in Treas. Reg. 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.
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. 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. 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. 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.
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. 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. 1.704-2.
(f) Partner Nonrecourse Deductions. Any Partner Nonrecourse
Deductions
for any fiscal year or other period shall be specially allocated to the
Partner
who bears the economic risk of loss with respect to the Partner Nonrecourse
Debt
to which such Partner Nonrecourse Deductions are attributable in accordance
with
Treas. Reg. 1.704-2(i).
(g) Code 754 Adjustments. To the extent an adjustment to the
adjusted
tax basis of any Partnership asset pursuant to Code 734(b) or 743(b)
is
required, pursuant to Treas. Reg. 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).
(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. 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 704(b). In order to preserve and protect the
allocations
provided for in this Article 3, the Managing General Partner shall have the
authority to allocate income, gain, loss, deduction or credit (or any item
thereof) arising in any year differently than that expressly provided for
in this
Article 3, if and to the extent that determining and allocating income,
gain,
loss, deduction or credit (or any item thereof) in the manner expressly
provided
for in this Article 3 would cause the allocations of each Partner's
distributive
share of income, gain, loss, deduction or credit (or any item thereof) not
to be
permitted by Code 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 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 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
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.
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 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 706(d) and the regulations thereunder. Each Partner's
share
of "allocable cash basis items" shall be determined in accordance with Code
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 706(d)(2)(B) and the regulations
thereunder.
ARTICLE IV
Distributions
4.01 Time of Distribution. Cash available for distribution shall be
determined by the Managing General Partner. The Managing General Partner
shall
distribute, in its discretion, such cash deemed available for distribution,
but
such distributions shall be made not less frequently than quarterly.
4.02 Distributions.
(a) Except as otherwise provided below and in Section 2.01(a), all
distributions (other than those made to wind up the Partnership in
accordance
with Section 9.03 hereof) shall be made 80% to the Investor Partners and 20%
to
the Managing General Partner. If the performance standard as defined
below
in subsection (b) is not fulfilled by a particular Partnership, that
Partnership's sharing arrangement shall be modified, as set forth herein,
for up
to a ten-year period commencing six months after the closing date of that
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 ten years 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
initial 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.
(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 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, 2003 [with respect to
Partnerships designated as "PDC 2001- Limited Partnership," January 1,
2004
with respect to Partnerships designated as "PDC 2002- Limited Partnership"
and
January 1, 2005 with respect to Partnerships designated as "PDC 2003-
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 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.
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 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.
(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:
(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.
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;
(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;
(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;
or
(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.
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.
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
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 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
(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.
(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 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 after 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.
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 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 Partners of any
Partnership, the Managing General Partner 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.
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 the Partnership Agreement and the exercise of Investor Partners'
rights
under federal proxy laws; and
(v) If the Managing General Partner of the Partnership neglects or
refuses to exhibit, produce, or mail a copy of the participant list as
requested,
the Managing General Partner shall be liable to any Investor Partner
requesting
the list for the costs, including attorneys fees, incurred by that Investor
Partner for compelling the production of the participant list, and for
actual
damages suffered by any Investor Partner by reason of such refusal or
neglect.
It shall be a defense that the actual purpose and reason for the requests
for
inspection or for a copy of the participant list is to secure the list of
Investor Partners or other information for the purpose of selling such list
or
information or copies thereof, or of using the same for a commercial purpose
other than in the interest of the applicant as an Investor Partner relative
to
the affairs of the Partnership. The Managing General Partner may require
the
Investor Partner requesting the participant list to represent that the list
is
not requested for a commercial purpose unrelated to the Investor Partner's
interest in the Partnership. The remedies provided hereunder to Investor
Partners requesting copies of the participant list are in addition to, and
shall
not in any way limit, other remedies available to Investor Partners under
federal
law, or the laws of any state.
8.02 Reports. The Managing General Partner shall deliver to each
Investor
Partner the following financial statements and reports at the times
indicated
below:
(a) Within 75 days after the end of the first six months of each
fiscal
year (for such six month period) and within 120 days after the end of each
fiscal
year (for such year), financial statements, including a balance sheet and
statements of income, Partners' equity, and cash flows, all of which shall
be
prepared in accordance with generally accepted accounting principles. The
annual
financial statements shall be accompanied by (i) a report of an independent
certified public accountant designated by the Managing General Partner
stating
that an audit of such financial statements has been made in accordance with
generally accepted auditing standards and that in its opinion such financial
statements present fairly the financial condition, results of operations,
and
cash flow of the Partnership in accordance with generally accepted
accounting
principles and (ii) a reconciliation of such financial statements with the
information furnished to the Investor Partners for federal income tax
reporting
purposes.
(b) Annually by March 15 of each year, a report containing such
information as may be deemed to enable each Investor Partner to prepare and
file
his federal income tax return and any required state income tax return.
(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).
(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 the 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.
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, 2050;
(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:
(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.
(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 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;
(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.
* * * * *
SIGNATURE PAGE
IN WITNESS WHEREOF, the undersigned have executed this Agreement as
of the
day and year first written above.
MANAGING GENERAL PARTNER: INITIAL LIMITED PARTNER:
Petroleum Development Corporation
103 East Main Street
Bridgeport, West Virginia 26330
Steven R. Williams
103 East Main Street Inc.
By:
Bridgeport, West Virginia 26330
Steven R. Williams
President
INVESTOR PARTNERS
COMPLETE TO INVEST AS ADDITIONAL GENERAL PARTNER
ADDITIONAL GENERAL PARTNER(S):
NUMBER OF UNITS Name:
PURCHASED (Print Name)
(Signature)
SUBSCRIPTION PRICE
$ Address:
By: Petroleum Development Corporation
By:
its
Attorney-in-Fact
COMPLETE TO INVEST AS LIMITED PARTNER
LIMITED PARTNER(S):
NUMBER OF UNITS Name:
PURCHASED (Print Name)
(Signature)
SUBSCRIPTION PRICE
$ Address:
By: Petroleum Development Corporation
By:
its
Attorney-in-Fact
EXHIBIT A
TO
AGREEMENT OF LIMITED PARTNERSHIP
OF
PDC 2001-___ LIMITED PARTNERSHIP,
[PDC 2002-___ LIMITED PARTNERSHIP,]
[PDC 2003-___ LIMITED PARTNERSHIP,]
A WEST VIRGINIA LIMITED PARTNERSHIP
Number of
Names and Addresses of Investors Nature of Interest
Units
APPENDIX B TO PROSPECTUS
PDC 2003 DRILLING PROGRAM
SUBSCRIPTION AGREEMENT
PDC 2001- Limited Partnership
[PDC 2002- Limited Partnership]
[PDC 2003- Limited Partnership]
I hereby agree to purchase ______ Unit(s) in the PDC 2001- Limited
Partnership [PDC 2002- Limited Partnership; PDC 2003- 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, I am aware
that a
broker may sell Units to me only if I qualify according to the express
suitability standards stated herein and in the Prospectus, and 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 2001 [2002; 2003] 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.
The above representations do not constitute a waiver of any rights
that I
may have under the statutes 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 natural gas; (B) the financial
hazards
involved in the offering, including the risk of losing my entire investment;
(C)
the lack of a public trading market for the Units and the lack of liquidity
of
this investment; (D) the restrictions on 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.
Date: , 2001.
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 box below):
IF NO SELECTION IS MADE, WE
CANNOT ACCEPT YOUR
? Units as an Additional General Partner SUBSCRIPTION AND WILL
HAVE
TO
RETURN THIS SUBSCRIPTION AGREE-
? Units as a Limited Partner MENT AND YOUR MONEY TO YOU.
Title to Units to be held (check box below):
? Individual Ownership ? Joint Tenants with Right of
Survivorship (both
persons
must sign)
? Tenants in Common (both
persons must sign) ? Other
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
, 2001
Area Code Telephone Number FC RR AE Signature
Date
WSH\42937.1
APPENDIX C TO PROSPECTUS
PDC 2003 DRILLING PROGRAM
SPECIAL SUBSCRIPTION INSTRUCTIONS
Checks for Units should be made payable to "Chase as Escrow Agent for
PDC
2001- Limited Partnership [PDC 2002- Limited Partnership; PDC 2003-
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 Investors.
? An Alaska investor must be (1) a person whose total purchase
does not
exceed 5% of his/her net worth if the purchase of securities is at least
$10,000,
and must have (2) either: (a) 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 (b) a minimum net worth of $225,000,
exclusive of principal automobile, principal residence, and home
furnishings.
Transfer of Units by Missouri Investors.
? 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.
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 2001 for Partnerships designated "PDC 2001- Limited
Partnership,"
2002 for Partnerships designated "PDC 2002- Limited Partnership," and 2003
for
Partnerships designated "PDC 2003- 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 2000 for Partnerships designated "PDC
2001-
Limited Partnership," 2001 for Partnerships designated "PDC 2002- Limited
Partnership" and 2002 for Partnerships designated PDC 2003- 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 (1)
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;
notwithstanding the foregoing, 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 in
expectation of an individual or combined taxable income of $60,000 or more
for
each of the current year and the succeeding year; or (2) 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 (3) have an individual or joint
minimum net worth with my spouse in excess of $500,000, exclusive of home,
home
furnishings and automobiles; or (4) have a combined minimum gross income of
$200,000 in the current year and the two previous years.
? If resident of South Dakota, I (1) 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
(2) 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 (3) have 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.
? If I am a Michigan, New Mexico, Ohio, Pennsylvania, or South
Dakota
resident, my investment in the Partnership will not be equal to or 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 (1) has a net worth of not less
than
$250,000 (exclusive of home, furnishings and automobiles) and had annual
gross
income during 2000 for Partnerships designated "PDC 2001- Limited
Partnership,"
2001 for Partnerships designated "PDC 2002- Limited Partnership" and 2002
for
Partnerships designated "PDC 2003- Limited Partnership" of $120,000 or
more, or
expects to have gross income in 2001 for Partnerships designated "PDC 2001-
Limited Partnership," 2002 for Partnerships designated "PDC 2002- Limited
Partnership" and 2000 for Partnerships designated "PDC 2003- Limited
Partnership of $120,000 or more, or (2) has a 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 2001 for
Partnerships designated "PDC 2001- Limited Partnership," 2002 for
Partnerships
designated "PDC 2002- Limited Partnership" and 2003 for Partnerships
designated
"PDC 2003- 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 2001 for Partnerships designated "PDC 2001- Limited
Partnership,"
2002 for Partnerships designated "PDC 2002- Limited Partnership" and 2003
for
Partnerships designated "PDC 2003- 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 2001 for Partnerships designated "PDC 2001- Limited
Partnership," 2002 for Partnerships designated "PDC 2002- Limited
Partnership"
and 2003 for Partnerships designated "PDC 2003- Limited Partnership of not
less
than $200,000.
? If a resident of California, I am aware that:
It is unlawful to consummate a sale or transfer of this security, or any
interest therein, or to receive any consideration therefor, without the
prior
written consent of the commissioner of corporations of the state of
California,
except as permitted in the commissioner's rules.
As a condition of qualification of the Units for sale in the State of
California, the following rule is hereby delivered to each California
purchaser.
California Administrative Code, Title 10, CH. 3, Rule 260.141.11.
Restriction on transfer. (a) The issuer of a security upon which a
restriction
on transfer has been imposed pursuant to Sections 260.102.6, 260.102.141.10,
and
260.534.10 shall cause a copy of this Section to be delivered to each issuee
or
transferee of such security at the time the certificate evidencing the
security
is delivered to the issuee or transferee.
(b) It is unlawful for the holder of any such security to consummate
a
sale or transfer of such security, or any interest therein, without the
prior
written consent of the Commissioner (until this condition is removed
pursuant to
Section 260.141.12 of these rules), except:
(1) to the issuer;
(2) pursuant to the order or process of any court;
(3) to any person described in Subdivision (i) of Section 25102 of
the
Code or Section 260.105.14 of these rules;
(4) to the transferor's ancestors, descendants or spouse, or any
custodian or trustee for the account of the transferor's ancestors,
descendants,
or spouse; or to a transferee by a trustee or custodian for the account of
the
transferee or the transferee's ancestors, descendants or spouse;
(5) to the holders of securities of the same class of the same
issuer;
(6) by way of gift or donation intervivos or on death;
(7) by or through a broker-dealer licensed under the Code (either
acting
as such or as a finder) to a resident of a foreign state, territory or
country
who is neither domiciled in this state to the knowledge of the
broker-dealer, nor
actually present in this state if the sale of such securities is not in
violation
of any securities law of the foreign state, territory or country concerned;
(8) to a broker-dealer licensed under the Code in a principal
transaction, or as an underwriter or member of an underwriting syndicate or
selling group;
(9) if the interest sold or transferred is a pledge or other lien
given
by the purchaser to the seller upon a sale of the security for which the
Commissioner's written consent is obtained or under this rule not required;
(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.
WSH\42941.1
[Comment1]
APPENDIX D TO THE PROSPECTUS
October 4, 2000
Petroleum Development Corporation
103 East Main Street
Bridgeport, West Virginia 26330
Re: PDC 2003 Drilling Program
Dear Sirs:
We have acted as counsel for PDC 2003 Drilling Program, in connection
with
the offer and sale of securities (the "Units") in a series of limited
partnerships, PDC 2001- Limited Partnerships, PDC 2002- Limited
Partnerships,
and PDC 2003- 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 with the Securities and
Exchange
Commission 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.
The following opinion and statements are based upon the provisions of
the
Internal Revenue Code of 1986, as amended (the "Code"), existing and
proposed
Treasury 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 2001, with respect to Partnerships designated "PDC
2001-_ Limited Partnership," 2002 with respect to Partnerships designated
"PDC
2002-_ Limited Partnership" and 2003 with respect to Partnerships designated
"PDC
2003-_ Limited Partnership."
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.
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.
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
the close of business on March 30, 2002 with respect to Partnerships
designated
"PDC 2001-_ Limited Partnership," March 30, 2003 with respect to
Partnerships
designated "PDC 2002-_ Limited Partnership," and March 30, 2004 with respect
to
Partnerships designated "PDC 2003-_ 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.
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.
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).
Treas. Reg. 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 Treas. Reg 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 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."
Due to the presence of the opinion of counsel condition, the
Partnership,
in our opinion, will not be treated as a PTP prior to the time any such
offers
are made to Investor Partners. Accordingly, the Partnership, in our
opinion,
will not be treated as a corporation for federal income tax purposes under
Code
section 7704 in the absence of the Partnership's interests being "readily
tradable on a secondary market (or the substantial equivalent thereof)."
Notwithstanding the above, the Service may promulgate regulations or
release announcements which take the position that interests in partnerships
such
as the Partnership are readily tradable on a secondary market or the
substantial
equivalent thereof. However, treatment of the Partnership as a PTP should
not
result in its treatment as a corporation for federal income tax purposes due
to
the exception contained in Code section 7704(c) relating to PTPs meeting
the 90%
of gross income test so long as such gross income test is satisfied.
C. Summary
In our opinion the Partnership will not be treated as an association
taxable as a corporation for federal income tax purposes by reason of the
Check
the Box Regulations. Further, since any right of the Managing General
Partner
to offer to purchase Units is conditioned upon the receipt of an opinion of
counsel that the Partnership will not be treated as a PTP, and assuming the
Partnership satisfies the 90% gross income test of Code section 7704, the
Partnership, in our opinion, will not be treated as a corporation for
federal
income tax purposes. Accordingly, the Partnership in our opinion will be
treated
as a partnership for federal income tax purposes. If challenged by the
Service
on this issue, the Partners should prevail on the merits, and each Partner
should
be required to report his proportionate share of the Partnership's items of
income and deductions on his individual federal income tax return.
If in any taxable year the Partnership were to be treated for federal
income tax purposes as a corporation or as an association taxable as a
corporation, the Partnership income, gain, loss, deductions, and credits
would
be reflected only on its "corporate" tax return rather than being passed
though
to the Partners. In such event, the Partnership would be required to pay
income
tax at corporate rates on its net income, thereby reducing the amount of
cash
available to be distributed to the Partners. Additionally, all or a portion
of
any distribution made to Partners would be taxable as dividends, which would
not
be deductible by the Partnership and which would generally be treated as
ordinary
portfolio income to the Partners, regardless of the source from which such
distributions were generated.
The discussion that follows is based on the assumption that the
Partnership
will be classified as a partnership for federal income tax purposes.
FEDERAL TAXATION OF THE PARTNERSHIP
Under the Code, a partnership is not a taxable entity and,
accordingly,
incurs no federal income tax liability. Rather, a partnership is a
"pass-through" entity which is required to file an information return with
the
Service. In general, the character of a partner's share of each item of
income,
gain, loss, deduction, and credit is determined at the partnership level.
Each
partner is allocated a distributive share of such items in accordance with
the
partnership agreement and is required to take such items into account in
determining the partner's income. Each partner includes such amounts in
income
for any taxable year of the partnership ending within or with the taxable
year
of the partner, without regard to whether the partner has received or will
receive any cash distributions from the Partnership.
REGISTRATION AS A TAX SHELTER
The Code provides that certain investments must be registered as tax
shelters with the Service. Registration numbers for such tax shelters must
be
supplied to investors who are required to report the numbers on their
personal
tax returns. Any organizer of a "potentially abusive tax shelter" and any
person
selling an interest in such shelter are required to maintain a list of
investors
in such tax shelter to whom interests were sold (together with other
identifying
information) and to make the list available to the Service upon request.
Any tax
shelter which is required to be registered and any other plan or arrangement
which is of a type determined by the Regulations as having a potential for
tax
avoidance or evasion is considered a potentially abusive tax shelter for
this
purpose.
The registration requirements apply only to an investment with respect
to
which any person could reasonably infer from the representations made, or
to be
made, in connection with the offering for sale of interests in the
investment
that the "tax shelter ratio" for any investor is greater than two to one as
of
the close of any of the first five years ending after the date on which such
investment is offered for sale.
The Managing General Partner has represented that, (i) based upon its
experience with its previous drilling programs and upon the intended
operations
of the Partnership, it does not believe that the Partnership will have a tax
shelter ratio greater than two to one, (ii) the deductions and credits that
are
or will be represented as potentially allowable to an investor will not
result
in any Partnership having a tax shelter ratio greater than two to one, and
(iii)
based upon a review of the economics of its similar oil and gas drilling
programs
for the past several years, it has determined that none of those programs
has
resulted in a tax shelter ratio greater than two to one. Accordingly, the
Managing General Partner does not intend to cause the Partnership to
register
with the Service as a tax shelter. Based on the foregoing representations,
we
are of the opinion that the Partnership will not be required to register
with the
Service as a tax shelter.
If it is subsequently determined that the Partnership was required to
be
registered with the Service as a tax shelter, the Partnership would be
subject
to certain penalties under IRC section 6707, including a penalty ranging
from
$500 to 1% of the aggregate amount invested in Units for failing to register
and
$100 for each failure to furnish to a Partner a tax shelter registration
number,
and each Partner would be liable for a $250 penalty for failure to include
the
tax registration number on his tax return, unless such failure was due to
reasonable cause. A Partner also would be liable for a penalty of $100 for
failing to furnish the tax shelter registration number to any transferee of
his
Partnership interest. Counsel can give no assurance that, if the
Partnership is
determined to be a tax shelter which must be registered with the Service,
the
above penalties will not apply.
INTANGIBLE DRILLING AND DEVELOPMENT COSTS DEDUCTIONS
Under Code section 263(a), taxpayers are denied deductions for
capital
expenditures, which expenditures are those that generally result in the
creation
of an asset having a useful life which extends substantially beyond the
close of
the taxable year. See also Treas. Reg. section 1.461-1(a)(2). In Indopco,
Inc.
v. Commissioner, 92-1 USTC paragraph 50,113 (1992) the Supreme Court seemed
to
further limit the capitalization criteria by stating that the costs should
be
capitalized when they provide benefits that extend beyond one tax year.
Notwithstanding these statutory and judicial general rules, Congress has
granted
to the Treasury Secretary the authority to prescribe regulations that would
allow
taxpayers the option of deducting, rather than capitalizing, intangible
drilling
and development costs ("IDC"). Code section 263. The Secretary's rules
are
embodied in Treas. Reg. section 1.612-4 and state that, in general, the
option
to deduct IDC applies only to expenditures for drilling and development
items
that do not have a salvage value.
With respect to IDC incurred by a partnership, Code section 703 and
Treas.
Reg. section 1.703-1(b) provide that the option to deduct such costs is to
be
exercised at the partnership level and in the year in which the deduction
is to
be taken. All partners are bound by the partnership's election. The
Managing
General Partner has represented that the Partnership will elect to deduct
IDC in
accordance with Treas. Reg. section 1.612-4. In this regard, Additional
General
Partners will be entitled to deduct IDC against any form of income in the
year
in which the investment is made, provided wells are spudded within the first
ninety days of the following year; subject to the same provision, Limited
Partners will be entitled to deduct IDC against passive income.
A. Classification of Costs
In general, IDC consists of those costs which in and of themselves
have no
salvage value. Treas. Reg. section 1.612-4(a) provides examples of items
to
which the option to deduct IDC applies, including all amounts paid for
labor,
fuel, repairs, hauling, and supplies, or any of them, which are used (i) in
the
drilling, shooting, and cleaning of wells, (ii) in such clearing of ground,
draining, road making, surveying, and geological works as are necessary in
the
preparation for the drilling of wells, and (iii) in the construction of such
derricks, tanks, pipelines, and other physical structures as are necessary
for
the drilling of wells and the preparation of wells for the production of oil
or
gas. The Service, in Rev. Rul. 70-414, 1970-2 C.B. 132, set forth further
classifications of items subject to the option and those considered capital
in
nature. The ruling provides that the following items are not subject to the
election of Treas. Reg. section 1.612-4(a): (i) oil well pumps (upon
initial
completion of the well), including the necessary housing structures; (ii)
oil
well pumps (after the well has flowed for a time), including the necessary
housing structures; (iii) oil well separators, including the necessary
housing
structures; (iv) pipelines from the wellhead to oil storage tanks on the
producing lease; (v) oil storage tanks on the producing lease; (vi) salt
water
disposal equipment, including any necessary pipelines; (vii) pipelines from
the
mouth of a gas well to the first point of control, such as a common carrier
pipeline, natural gasoline plant, or carbon black plant; (viii) recycling
equipment, including any necessary pipelines; and (ix) pipelines from oil
storage
tanks on the producing leasehold to a common carrier pipeline.
A partnership's classification of a cost as IDC is not binding on the
government, which might reclassify an item labeled as IDC as a cost which
must
be capitalized. In Bernuth v. Commissioner, 57 T.C. 225 (1971), aff'd, 470
F.2d
710 (2nd Cir. 1972), the Tax Court denied taxpayers a deduction for that
portion
of a turnkey drilling contract price that was in excess of a reasonable cost
for
drilling the wells in question under a turnkey contract, holding that the
amount
specified in the turnkey contract was not controlling. Similarly, the
Service,
in Rev. Rul. 73-211, 1973-1 C.B. 303, concluded that excessive turnkey costs
are
not deductible as IDC:
[O]nly that portion of the amount of the taxpayer's total investment that
is
attributable to intangible drilling and development costs that would have
been
incurred in an arm's-length transaction with an unrelated drilling
contractor (in
accordance with the economic realities of the transaction) is deductible [as
IDC].
To the extent the Partnership's prices meet the reasonable price
standards
imposed by Bernuth, supra, and Rev. Rul 73-211, supra, and to the extent
such
amounts are not allocable to tangible property, leasehold costs, and the
like,
the amounts paid to the Managing General Partner under the drilling contract
should qualify as IDC and should be deductible at the time described below
under
"B. Timing of Deductions." That portion of the amount paid to the Managing
General Partner that is in excess of the amount that would be charged by an
independent driller under similar conditions will not qualify as IDC and
will be
required to be capitalized.
We are unable to express an opinion regarding the reasonableness or
proper
characterization of the payments under the drilling agreement, since the
determination of whether the amounts are reasonable or excessive is
inherently
factual in nature. No assurance can be given that the Service will not
characterize a portion of the amount paid to the Managing General Partner
as an
excessive payment, to be capitalized as a leasehold cost, assignment fee,
syndication fee, organization fee, or other cost, and not deductible as IDC.
To
the extent not deductible, such amounts will be included in the Partners'
bases
of their interests in the Partnership.
B. Timing of Deductions
As described above, Code section 263(c) and Treas. Reg. section
1.612-4
allow the Partnership to expense IDC as opposed to capitalizing such
amounts.
Even if the Partnership elects to expense the IDC, assuming a taxpayer is
otherwise entitled to such a deduction, the taxpayer may elect to capitalize
all
or a part of the IDC and amortize same on a straight-line basis over a sixty
month period, beginning with the taxable month in which such expenditure is
made.
Code section 59(e)(1) and (2)(c).
For taxpayers entitled to deduct IDC, the timing of such deduction can
vary, depending, in part, upon the taxpayer's method of accounting. The
Managing
General Partner has represented that the Partnership will use the accrual
method
of accounting. Under the accrual method, income is recognized when all the
events have occurred which fix the right to receive such income and the
amount
thereof can be determined with reasonable accuracy. Treas. Reg. section
1.451-1(a). With respect to deductions, recognition results when all events
which establish liability have occurred and the amount thereof can be
determined
with reasonable accuracy. Treas. Reg. section 1.461-1(a)(2). Regarding
deductions, Code section 461(h)(1) provides that ". . . the all events test
shall not be treated as met any earlier than when economic performance with
respect to such item occurs."
Code section 461(i)(2), provides that, in the case of a "tax
shelter,"
economic performance with respect to the act of drilling an oil or gas well
will
". . . be treated as having occurred within a taxable year if drilling of
the
well commences before the close of the 90th day after the close of the
taxable
year." "Tax shelter," for purposes of Code section 461, is defined to
include
the Partnership. However, with respect to a tax shelter which is a
partnership,
the maximum deduction that would be allowable for any prepaid expenses under
this
exception would be limited to the partner's "cash basis" in the partnership.
Code section 461(i)(2)(B)(i). Such "cash basis" equals the partner's
adjusted
basis in the partnership, determined without regard to (i) any liability of
the
partnership and (ii) any amount borrowed by the partner with respect to the
partnership which (I) was arranged by the partnership or by any person who
participated in the organization, sale, or management of the partnership (or
any
person related to such person within the meaning of Code section
465(b)(3)(C))
or (II) was secured by any assets of the partnership. Code section
461(i)(2)(C). The Managing General Partner has represented that, as
Operator,
it will commence drilling operations by spudding each well on or before
March 30,
2002 for Partnerships designated "PDC 2001-_ Limited Partnership," March 30,
2003
for Partnerships designated "PDC 2002-_ Limited Partnership," and March 30,
2004
for Partnerships designated "PDC 2003-_ 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.
The Managing General Partner is unable to represent that all of the
Wells
will be completed in 2001 for Partnerships designated "PDC 2001-_ Limited
Partnership," 2002 for Partnerships designated "PDC 2002-_ Limited
Partnership,"
and 2003 for Partnerships designated "PDC 2003-_ Limited Partnership";
however,
the Managing General Partner has represented that any Well that is not
completed
in 2001 with respect to Partnerships designated "PDC 2001-_ Limited
Partnership,"
in 2002 with respect to Partnerships designated "PDC 2002-_ Limited
Partnership,"
and in 2003 with respect to Partnerships designated "PDC 2003-_ Limited
Partnership" will be spudded by not later than March 30, 2002 for
Partnerships
designated "PDC 2001-_ Limited Partnership," March 30, 2003 for Partnerships
designated "PDC 2002-_ Limited Partnership," and March 30, 2004 for
Partnerships
designated "PDC 2003-_ 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.
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.
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, 2002 for
Partnerships designated "PDC 2001-_ Limited Partnership," March 30, 2003 for
Partnerships designated "PDC 2002-_ Limited Partnership," and March 30, 2004
for
Partnerships designated "PDC 2003-_ 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
2001 for Partnerships designated "PDC 2001-_ Limited Partnership," 2002 for
Partnerships designated "PDC 2002-_ Limited Partnerships," and 2003 for
Partnerships designated "PDC 2003-_ Limited Partnership" will be allowable
as a
deduction in 2001 for Partnerships designated "PDC 2001-_ Limited
Partnership,"
2002 for Partnerships designated "PDC 2002-_ Limited Partnerships," and 2003
for
Partnerships designated "PDC 2003-_ 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
2001 for Partnerships designated "PDC 2001-_ Limited Partnership," 2002 for
Partnerships designated "PDC 2002-_ Limited Partnerships," and 2003 for
Partnerships designated "PDC 2003-_ 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 2002 for Partnerships designated "PDC 2001-_ Limited
Partnership," 2003 for Partnerships designated "PDC 2002-_ Limited
Partnership,"
and 2004 for Partnerships designated "PDC 2003-_ Limited Partnership" are
not
deductible in whole or in part until 2002 or 2003 or 2004, respectively.
Further, to the extent drilling of the Partnership's wells does not commence
by
March 30, 2002 for Partnerships designated "PDC 2001-_ Limited Partnership,"
March 30, 2003 for Partnerships designated "PDC 2002-_ Limited Partnership,"
and
March 30, 2004 for Partnerships designated "PDC 2003-_ Limited Partnership,"
the
deductibility of all or a portion of the IDC may be deferred under Code
section
461.
C. Recapture of IDC
IDC which has been deducted is subject to recapture as ordinary income
upon
certain dispositions (other than by abandonment, gift, death, or tax-free
exchange) of an interest in an oil or gas property. IDC previously deducted
that
is allocable to the property (directly or through the ownership of an
interest
in a partnership) and which would have been included in the adjusted basis
of the
property is recaptured to the extent of any gain realized upon the
disposition
of the property. Treasury regulations provide that recapture is determined
at
the partner level (subject to certain anti-abuse provisions). Treas. Reg.
section 1.1254-5(b). Where only a portion of recapture property is
disposed of,
any IDC related to the entire property is recaptured to the extent of the
gain
realized on the portion of the property sold. In the case of the
disposition of
an undivided interest in a property (as opposed to the disposition of a
portion
of the property) a proportionate part of the IDC with respect to the
property is
treated as allocable to the transferred undivided interest to the extent of
any
realized gain. Treas. Reg. section 1.1254-1(c).
DEPLETION DEDUCTIONS
The owner of an economic interest in an oil and gas property is
entitled
to claim the greater of percentage depletion or cost depletion with respect
to
oil and gas properties which qualify for such depletion methods. In the
case of
partnerships, the depletion allowance must be computed separately by each
partner
and not by the partnership. Code section 613A(c)(7)(D). Notwithstanding
this
requirement, however, the Partnership, pursuant to Section 3.01(d)(i) of the
Partnership Agreement, will compute a "simulated depletion allowance" at the
Partnership level, solely for the purposes of maintaining Capital Accounts.
Code
sections 613A(d)(2) and 613A(d)(4).
Cost depletion for any year is determined by multiplying the number
of
units (e.g., barrels of oil or Mcf of gas) sold during the year by a
fraction,
the numerator of which is the cost of the mineral interest and the
denominator
of which is the estimated recoverable units of reserve available as of the
beginning of the depletion period. See Treas. Reg. section 1.611-2(a).
In no
event can the cost depletion exceed the adjusted basis of the property to
which
it relates.
Percentage depletion is generally available only with respect to the
domestic oil and gas production of certain "independent producers." In
order to
qualify as an independent producer, the taxpayer, either directly or through
certain related parties, may not be involved in the refining of more 50,000
barrels of oil (or equivalent of gas) on any day during the taxable year or
in
the retail marketing of oil and gas products exceeding $5 million per year
in the
aggregate.
In general, (i) component members of a controlled group of
corporations,
(ii) corporations, trusts, or estates under common control by the same or
related
persons and (iii) members of the same family (an individual, his spouse and
minor
children) are aggregated and treated as one taxpayer in determining the
quantity
of production (barrels of oil or cubic feet of gas per day) qualifying for
percentage depletion under the independent producer's exemption. Code
section
613A(c) (8). No aggregation is required among partners or between a partner
and
a partnership. An individual taxpayer is related to an entity engaged in
refining or retail marketing if he owns 5% or more of such entity. Code
section
613A(d)(3).
Percentage depletion is a statutory allowance pursuant to which, under
current law, a minimum deduction equal to 15% of the taxpayer's gross income
from
the property is allowed in any taxable year, in general not to exceed (i)
100%
of the taxpayer's taxable income from the property (computed without the
allowance for depletion) or (ii) 65% of the taxpayer's taxable income for
the
year (computed without regard to percentage depletion and net operating loss
and
capital loss carrybacks). Code sections 613(a) and 613A(d)(1). In the case
of
"stripper well property," as that term is defined in Code section
613A(c)(6)(D),
the 100% of taxable income limitation has been eliminated for taxable years
1998
to 2001. 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 up to 25%. Code 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 Code
section
1254.
Since the availability of percentage depletion for a partner is
dependent
upon the status of the partner as an independent producer, we also are
unable to
express an opinion on this matter. Because of the foregoing, we are unable
to
render any opinion as to the availability of percentage depletion. Each
prospective investor is urged to consult with his personal tax advisor to
determine whether percentage depletion would be available to him.
DEPRECIATION DEDUCTIONS
The Partnership will claim depreciation, cost recovery, and
amortization
deductions with respect to its basis in Partnership Property as permitted
by the
Code. For most tangible personal property placed in service after December
31,
1986, the "modified accelerated cost recovery system" ("MACRS") must be used
in
calculating the cost recovery deductions. Thus, the cost of lease equipment
and
well equipment, such as casing, tubing, tanks, and pumping units, and the
cost
of oil or gas pipelines cannot be deducted currently but must be capitalized
and
recovered under "MACRS." The cost recovery deduction for most equipment
used in
domestic oil and gas exploration and production and for most of the tangible
personal property used in natural gas gathering systems is calculated using
the
200% declining balance method switching to the straight-line method, a
seven-year
recovery period, and a half-year convention.
INTEREST DEDUCTIONS
In the Transaction, the Investor Partners will acquire their interests
by
remitting cash in the amount of $20,000 per Unit to the Partnership. In no
event
will the Partnership accept notes in exchange for a Partnership interest.
Nevertheless, without any assistance of the Managing General Partner or any
of
its affiliates, some Partners may choose to borrow the funds necessary to
acquire
a Unit and may incur interest expense in connection with those loans. Based
upon
the purely factual nature of any such loans, we are unable to express an
opinion
with respect to the deductibility of any interest paid or incurred thereon.
TRANSACTION FEES
The Partnership may classify a portion of the fees (the "Fees") to be
paid
to third parties and to the Managing General Partner or to the Operator and
its
affiliates (as described in the Prospectus under "Source of Funds and Use
of
Proceeds") as expenses which are deductible as organizational expenses or
otherwise. There is no assurance that the Service will allow the
deductibility
of such expenses and counsel expresses no opinion with respect to the
allocation
of the Fees to deductible and nondeductible items.
Generally, expenditures made in connection with the creation of, and
with
sales of interests in, a partnership will fit within one of several
categories.
A partnership may elect to amortize and deduct its organizational
expenses
(as defined in Code section 709(b)(2) and in Treas. Reg. section
1.709-2(a))
ratably over a period of not less than 60 months commencing with the month
the
partnership begins business. Organizational expenses are expenses which (i)
are
incident to the creation of the partnership, (ii) are chargeable to capital
account, and (iii) are of a character which, if expended incident to the
creation
of a partnership having an ascertainable life, would (but for Code section
709(a)) be amortized over such life. Id. Examples of organizational
expenses
are legal fees for services incident to the organization of the partnership,
such
as negotiation and preparation of a partnership agreement, accounting fees
for
services incident to the organization of the partnership, and filing fees.
Treas. Reg. section 1.709-2(a).
Under Code section 709, no deduction is allowable for "syndication
expenses," examples of which include brokerage fees, registration fees,
legal
fees of the underwriter or placement agent and the issuer (general partners
or
the partnership) for securities advice and for advice pertaining to the
adequacy
of tax disclosures in the prospectus or private placement memorandum for
securities law purposes, printing costs, and other selling or promotional
material. These costs must be capitalized. Treas. Reg. section
1.709-2(b).
Payments for services performed in connection with the acquisition of
capital
assets must be amortized over the useful life of such assets. Code section
263.
Under Code section 195, no deduction is allowable with respect to
"start-up expenditures," although such expenditures may be capitalized and
amortized over a period of not less than 60 months. Start-up expenditures
are
defined as amounts (i) paid or incurred in connection with (I) investigating
the
creation or acquisition of an active trade or business, (II) creating an
active
trade or business, or (III) any activity engaged in for profit and for the
production of income before the day on which the active trade or business
begins,
in anticipation of such activity becoming an active trade or business, and
(ii)
which, if paid or incurred in connection with the operation of an existing
active
trade or business (in the same field as the trade or business referred to
in (i)
above), would be allowable as a deduction for the taxable year in which paid
or
incurred. Code section 195(c)(1).
The Partnership intends to make payments to the Managing General
Partner,
as described in greater detail in the Prospectus. To be deductible,
compensation
paid to a general partner must be for services rendered by the partner other
than
in his capacity as a partner or for compensation determined without regard
to
partnership income. Fees which are not deductible because they fail to meet
this
test may be treated as special allocations of income to the recipient
partner
(see Pratt v. Commissioner, 550 F.2d 1023 (5th Cir. 1977)), and thereby
decrease
the net loss or increase the net income among all partners.
To the extent these expenditures described in the Prospectus are
considered
syndication costs (such as the fees paid to brokers and broker-dealers, and
the
fees paid for printing the Prospectus and possibly all or a portion of the
Managing General Partner's management fee), they will be nondeductible by
the
Partnership. To the extent attributable to organization fees (such as the
amounts paid for legal services incident to the organization of the
Partnership),
the expenditures may be amortizable over a period of not less than 60
months,
commencing with the month the Partnership begins business, if the
Partnership so
elects; if no election is made, no deduction is available. Finally, to the
extent any portion of the expenditures would be treated as "start-up," they
could
be amortized over a 60 month or longer period, provided the proper election
was
made.
Due to the inherently factual nature of the proper allocation of
expenses
among nondeductible syndication expenses, amortizable organization expenses,
amortizable "start-up" expenditures, and currently deductible items, and
because
the issues involve questions concerning both the nature of the services
performed
and to be performed and the reasonableness of amounts charged, we are unable
to
express an opinion regarding such treatment. If the Service were to
successfully
challenge the Managing General Partner's allocations, a Partner's taxable
income
could be increased, thereby resulting in increased taxes and in liability
for
interest and penalties.
BASIS AND AT RISK LIMITATIONS
A Partner's share of Partnership losses will not be allowed as a
deduction
to the extent such share exceeds the amount of the Partner's adjusted tax
basis
in his Units. A Partner's initial adjusted tax basis in his Units will
generally
be equal to the cash he has invested to purchase his Units. Such adjusted
tax
basis will generally be increased by (i) additional amounts invested in the
Partnership, including his share of net income, (ii) additional capital
contributions, if any, and (iii) his share of Partnership borrowings, if
any,
based on the extent of his economic risk of loss for such borrowings. Such
adjusted tax basis will generally be reduced, but not below zero by (i) his
share
of loss, (ii) his depletion deductions on his share of oil and gas income
(until
such deductions exhaust his share of the basis of property subject to
depletion),
(iii) distributions of cash and the adjusted basis of property other than
cash
made to him, and (iv) his share of reduction in the amount of indebtedness
previously included in his basis.
In addition, Code section 465 provides, in part, that, if an
individual
or a closely held C (i.e., regularly taxed) corporation engages in any
activity
to which Code 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).
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.
he 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).
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).
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 Temp. 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
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) generally 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, if an Additional General
Partner interest is converted to a limited partner interest prior to the
spudding
date, but after the end of the taxable year in which IDC was incurred, IDC
will
be subject to the passive activity rules. See Treas. Reg. section
1.469-1T(e)(4). In addition, that portion of Partnership gross income for
such
prior taxable year attributable to IDC treated as passive loss will be
considered
passive income. The "spudding date" is the date that drilling commences.
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, Temp. Treas. Reg. section 1.469-1T(e)(4)(iii),
example
(1), respect the nature of a general partnership interest prior to its
conversion
into limited partnership form:
A, a calendar year individual, acquires on January 1, 1987, a general
partnership
interest in P, a calendar year partnership that holds a working interest in
an
oil or gas property. Pursuant to the partnership agreement, A is entitled
to
convert the general partnership interest into a limited partnership interest
at
any time. On December 1, 1987, pursuant to a contract with D, an
independent
drilling contractor, P commences drilling a single well pursuant to the
working
interest. Under the drilling contract, P pays D for the drilling only as
the
work is performed. All drilling costs are deducted by P in the year in
which
they are paid. At the end of 1987, A converts the general partnership
interest
into a limited partnership interest, effective immediately. The drilling
of the
well is completed on February 28, 1988.
Since, in the example, A holds the working interest through an entity that
does
not limit A's liability throughout 1987 and through an entity that does
limit A's
liability in 1988, the example in the regulation concludes that A's interest
in
P's well is not an interest in a passive activity for 1987 but is an
interest in
a passive activity for 1988.
If an Additional General Partner converts his interest to a Limited
Partner
interest pursuant to the terms of the Partnership Agreement, the character
of a
subsequently generated tax attribute will be dependent upon, inter alia, the
nature of the tax attribute and whether there arose, prior to conversion,
losses
to which the working interest exception applied.
Assuming the activities of a converting partner will not result in the
Partner's being treated as materially participating under Temp. Treas. Reg.
section 1.469-5T(a)(1), (5), or (6), as described above, the Limited
Partner's
activity after conversion should be treated as a passive activity. Code
section
469(c)(1). Accordingly, any loss arising therefrom should be treated as a
PAL
under Code section 469(d), with the benefits thereof limited by Code
section
469(a)(1), as described above. However, Code section 469(c)(3)(B) provides
that, if a taxpayer has any loss from any taxable year from a working
interest
in any oil or gas property that is treated as a non-passive loss, then any
net
income from such property for any succeeding taxable year is to be treated
as
income that is not from a passive activity. Consequently, assuming that a
converting Additional General Partner has losses from working interests
which are
treated as non-passive, income from the Partnership allocable to the Partner
after conversion would be treated as income that is not from a passive
activity.
C. Limited Partner Interests
If an Investor Partner (other than an Additional General Partner who
converts his interest into that of a Limited Partner) invests in the
Partnership
as a Limited Partner, in the opinion of counsel, his distributive share of
the
Partnership's losses will be treated as PALs, the availability of which will
be
limited to the Partner's passive income for such year. If the Partner does
not
have sufficient passive income to utilize the PAL, the disallowed PAL will
be
suspended and may be carried forward (but not back) to be deducted against
passive income arising in future years. Further, upon the complete
disposition
of the interest to an unrelated party, in a fully taxable transaction such
suspended losses will be available, as described above.
Regarding Partnership income, Limited Partners should generally be
entitled
to offset their distributive shares of such income with deductions from
other
passive activities, except to the extent such Partnership income is
portfolio
income. Since gross income from interest, dividends, annuities, and
royalties
not derived in the ordinary course of a trade or business is not passive
income,
a Limited Partner's share of income from royalties, income from the
investment
of the Partnership's working capital, and other items of portfolio income
will
not be treated as passive income. In addition, Code section 469(l)(3)
grants
the Secretary of the Treasury the authority to prescribe regulations
requiring
net income or gain from a limited partnership or other passive activity to
be
treated as not from a passive activity.
D. Publicly Traded Partnerships
Notwithstanding the above, Code section 469(k) treats net income from
PTPs
as portfolio income under the PAL rules. Further, each partner in a PTP is
required to treat any losses from a PTP as separate from income and loss
from any
other PTP and also as separate from any income or loss from passive
activities.
Id. Losses attributable to an interest in a PTP that are not allowed under
the
passive activity rules are suspended and carried forward, as described
above.
Further, upon a complete taxable disposition of an interest in a PTP, any
suspended losses are allowed (as described above with respect to the passive
loss
rules). As noted above, we have opined that the Partnership will not be a
PTP.
In the event the Partnership were treated as a PTP, any net income
would
be treated as portfolio income and each Partner's loss therefrom would be
treated
as separate from income and loss from any other PTP and also as separate
from any
income or loss from passive activities. Since the Partnership should not
be
treated as a PTP, the provisions of Code section 469(k), in our opinion,
will
not apply to the Partners in the manner outlined above prior to the time
that
such Partnership becomes a PTP. However, unlike the PTP rules of Code
section
7704, the passive activity rules of Code section 469 do not provide an
exception
for partnerships that pass the 90% test of Code section 7704. Accordingly,
if
the Partnership were to be treated as a PTP under the passive activity
rules,
passive losses could be used only to offset passive income from the
Partnership.
CONVERSION OF INTERESTS
Code section 708 provides that a partnership will be considered as
terminated for federal income tax purposes if, inter alia, there is "a sale
or
exchange of 50 percent or more of the total interest in partnership capital
and
profits" within a 12 month period. If a conversion of an Additional General
Partner's interest into a Limited Partner interest were treated as a "sale
or
exchange" for purposes of Code section 708, the Partnership would be
terminated
for federal income tax purposes if 50% or more of the profits and capital
interests in the Partnership were sold or exchanged within a 12 month
period.
In Rev. Rul. 84-52, 1984-1 C.B. 157, the Service ruled that the
conversion
of a general partnership interest into a limited partnership interest in the
same
partnership will not give rise to the recognition of gain or loss under Code
section 741 or section 1001. The holding of Rev. Rul. 84-52 was confirmed
in
Rev. Rul. 95-37, 1995-1 C.B. 130. The ruling noted that, under Code section
721, no gain or loss is recognized by a partnership or any of its partners
upon
the contribution of property to the partnership in exchange for an interest
therein. Consequently, the partnership will not be terminated under Code
section
708 since (i) the business of the partnership will continue after the
conversion
and (ii) 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 Code section
1245
property is disposed of, the amount by which the lower of (i) the property's
recomputed basis or (ii) the amount realized (on the sale, exchange, or
involuntary conversion) of the property or the fair market value (on any
other
disposition) of the property exceeds the property's adjusted basis is to be
treated as ordinary income. Code section 1245(b)(3) provides that, if the
basis
of the property in the hands of the transferee is determined by reference
to its
basis in the hands of the transferor by reason of, inter alia, Code section
721,
then the gain taken into account for purpose of Code section 1245(a) is not
to
exceed the gain taken into account by the transferor of such property
(without
regard to Code section 1245(b)). To the extent the conversion of General
Partner interests to Limited Partner interests is governed by Code section
721,
the converting Partner will only be required to include in ordinary income
the
amount of gain he otherwise would recognize with respect to the "Section
1245"
property attributable to him.
Code section 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).
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).
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).
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(a)(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 6722 provides that persons who fail to furnish this information to
the
partnership will be penalized $50 for each such failure, or, if such failure
is
due to intentional disregard to the filing requirement, the person will be
penalized the greater of (i) $100 or (ii) 10% of the aggregate amount to be
reported. Furthermore, a partnership is required to notify the Service of
any
sale or exchange of interests of which it has notice, and to report the
names and
addresses of the transferee and the transferor, along with all other
required
information. The partnership also is required to provide copies of the
information it provides to the Service to the transferor and the transferee.
The tax consequences to an assignee purchaser of a Unit from a Partner
are
not described herein. Any assignor of a Unit should advise his assignee to
consult his own tax advisor regarding the tax consequences of such
assignment.
PARTNERSHIP DISTRIBUTIONS
Under the Code, any increase in a partner's share of partnership
liabilities, or any increase in such partner's individual liabilities by
reason
of an assumption by him of partnership liabilities is considered to be a
contribution of money by the partner to the partnership. Similarly, any
decrease
in a partner's share of partnership liabilities or any decrease in such
partner's
individual liabilities by reason of the partnership's assumption of such
individual liabilities will be considered as a distribution of money to the
partner by the partnership. Code section 752(a), (b).
The Partners' adjusted bases in their Units will initially consist of
the
cash they contribute to the Partnership. Their bases will be increased by
their
share of Partnership income and additional contributions and decreased by
their
share of Partnership losses and distributions. To the extent that such
actual
or constructive distributions are in excess of a Partner's adjusted basis
in his
Partnership interest (after adjustment for contributions and his share of
income
and losses of the Partnership), that excess will generally be treated as
gain
from the sale of a capital asset. In addition, gain could be recognized to
a
distributee partner upon the disproportionate distribution to a partner of
unrealized receivables, substantially appreciated inventory or, in some
cases,
Code 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."
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).
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. section 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(k)(3), Treas. Reg. sections 301.6110-2(a)
and
-7(b). Nevertheless, TAMs do serve to illustrate the Service's position on
certain specific cases. The TAMs relating to substantial economic effect
focus
on the tax avoidance purpose of any such above-described allocations and on
the
partnership plan for distributions upon liquidation. Illustrative of the
Service's approach is TAM 8008054, in which the Service concluded that an
allocation to the partners solely of items that the partnership had elected
to
expense (IDC) had as its principal purpose tax avoidance. The Service
suggested
that, had the allocation affected the parties' liquidation rights, the
allocation
would have had substantial economic effect: "In general, substantial
economic
effect has been found where all allocations of items of income, gain, loss,
deduction or credit increase or decrease the respective capital accounts of
the
partners and distribution of assets made upon liquidation is made in
accordance
with capital accounts." The ruling noted that the investors "should have
been
allocated their share of costs over the intangible drilling costs." Id.
The
question whether economic effect is "substantial" is one of fact which may
depend
in part on the timing of income and deductions and on consideration of the
investors' tax attributes unrelated to their investment in Units, and thus
is not
a question upon which a legal opinion 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. Treas. Reg. section 1.613A-3(e)(2). The terms "capital" and
"income"
are not defined in the Code or in the Regulations under Code 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 Code
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 and Distribution Shifts. Section 3.02(a) of the
Partnership
Agreement provide 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. Section 4.02(b)(i) of the Partnership Agreement provides for
a
corresponding shift in the allocation of Partnership income.
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. Thus, nonrecourse deductions must be allocated in
accordance
with the partners' interests in the partnership. Treas. Reg. section
1.704-2(b)(1).
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 Treas. Reg. 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 excess nonrecourse
liabilities of the Partnership. Treas. Reg. section 1.752-3. For this
purpose,
the Partnership Agreement provides for the allocation of excess nonrecourse
liabilities of 80% to the Investor Partners and 20% to the Managing General
Partner.
Retroactive Allocations. To prevent retroactive allocations of
partnership
tax attributes to partners entering into a partnership late in the tax year,
Code
section 706(d) provides that a partner's distributive share of such
attributes
is to be determined by the use of methods prescribed by the Treasury
Secretary
which take into account the varying interests of the partners during the
taxable
year.
The Partnership Agreement, at Section 3.04(c), provides that each
Partner's
allocation of tax items other than "allocable cash basis items" is to be
determined under a method permitted by Code section 706(d) and the
regulations
thereunder. With respect to "allocable cash basis items," Section 3.04(c)
requires an allocation in accordance with the requirements of Code section
706(d).
Accordingly, the Partnership allocations should be considered to be
in
accordance with the provisions of Code section 706(d).
PROFIT MOTIVE
The existence of economic, nontax motives for entering into the
Transaction
is essential if the Partners are to obtain the tax benefits associated with
an
investment in the Partnership.
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
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 183, that "a taxpayer has the right to
engage in
a venture which has economic substance even though his motivation in the
early
years of the venture may have been to obtain a deduction to offset taxable
income." Lemmen v. Commissioner, 77 T.C. 1326, 1346 (1981), acq., 1983-1
C.B.
1.
Due to the inherently factual nature of a Partner's intent and motive
in
engaging in the Transaction, we do not express an opinion as to the ultimate
resolution of this issue in the event of a challenge by the Service.
Partners
must, however, seek to make a profit from their activities with respect to
the
Transaction beyond any tax benefits derived from those activities or risk
losing
those tax benefits.
TAX AUDITS
Subchapter C of Chapter 63 of the Code provides that administrative
proceedings for the assessment and collection of tax deficiencies
attributable
to a partnership must be conducted at the partnership, rather than the
partner,
level. Partners will be required to treat Partnership items of income,
gain,
loss, deduction, and credit in a manner consistent with the treatment of
each
such item on the Partnership's returns unless such Partner files a statement
with
the Service identifying the inconsistency. If the Partnership is audited,
the
tax treatment of each item will be determined at the Partnership level in
a
unified partnership proceeding. Conforming adjustments to the Partners' own
returns will then occur unless such partner can establish a basis for
inconsistent treatment (subject to waiver by the Service).
PDC will be designated the "tax matters partner" ("TMP") for the
Partnership and will receive notice of the commencement of a Partnership
proceeding and notice of any administrative adjustments of Partnership
items.
The TMP is entitled to invoke judicial review of administrative
determinations
and to extend the period of limitations for assessment of adjustments
attributable to Partnership items. Each Partner will receive notice of the
administrative proceedings from the TMP and will have the right to
participate
in the administrative proceeding pursuant to tax requirements of Treas. Reg.
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.
PENALTIES
Under Code 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. Code 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
Code 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.
Code
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).
Code
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 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.
Code
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. Code section
6662(d)(2)(C)(ii).
It is important to note that this definition of "tax shelter" differs from
that
contained in Code sections 461 and 6111, as discussed above. A tax shelter
item
includes an item of income, gain, loss, deduction, or credit that is
directly or
indirectly attributable to a partnership that is formed for the principal
purpose
of avoiding or evading federal income tax. The existence of substantial
authority is determined as of the time the taxpayer's return is filed or on
the
last day of the taxable year to which the return relates and not when the
investment is made. Treas. Reg. section 1.6662-4(d)(3)(iv)(C).
Substantial
authority exists if the weight of authorities supporting a position is
substantial compared with the weight of authorities supporting contrary
treatment. Treas. Reg. section 1.6662-4(d)(3)(i). Relevant authorities
included statutes, Regulations, court cases, revenue rulings and procedures,
and
Congressional intent. However, among other things, conclusions reached in
legal
opinions are not considered authority. Treas. Reg. section
1.6662-4(d)(3)(iii).
The Secretary may waive all or a portion of the penalty imposed under Code
section 6662 upon a showing by the taxpayer that there was reasonable cause
for
the understatement and that the taxpayer acted in good faith. Code section
6664(d).
Although not anticipated by PDC, there may not be substantial
authority for
one or more reporting positions that the Partnership may take in its federal
income tax returns. In such event, if the Partnership does not disclose or
if
it fails to adequately disclose any such position, or if such disclosure is
deemed adequate but it is determined that there was no reasonable basis for
the
tax treatment of such a partnership item, the penalty will be imposed with
respect to any substantial understatement determined to have been made,
unless
the provisions of the Regulations pertaining to waiver of the penalty become
final and the Partnership is able to show reasonable cause and good faith
in
making the understatement as specified in such provisions. If the
Partnership
makes a disclosure for the purposes of avoiding the penalty, the disclosure
is
likely to result in an audit of such return and a challenge by the Service
of
such position taken.
If it were determined that a Partner had underpaid tax for any taxable
year, such Partner would have to pay the amount of underpayment plus
interest on
the underpayment from the date the tax was originally due. The interest
rate on
underpayments is determined by the Service based upon the federal short term
rate
of interest (as defined in Code section 1274(d)) plus 3%, or 5% for large
corporate underpayments, and is compounded daily. The rate of interest is
adjusted monthly.
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, u
section
p 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.
SOCIAL SECURITY BENEFITS; SELF-EMPLOYMENT TAX
A General Partner's share of any income or loss attributable to his
investment in Units will constitute "net earnings from self-employment" for
either social security or self-employment tax purposes. The Social Security
Act
and the Code exclude from the definition of "net earnings from
self-employment"
a limited partner's distributive share of any item of income or loss from
a
partnership other than a guaranteed payment for personal services actually
rendered. Therefore, a Limited Partner's share of income or loss
attributable
to his investment in Units will not constitute "net earnings from
self-employment" for either social security or self-employment purposes.
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
EXHIBIT INDEX
NUMBER DESCRIPTION PAGE
10.2 Escrow Agreements with PNC Bank, N.A.
23.1. Consent of Duane, Morris & Heckscher LLP
(included in Part II of Registrant Statement).
23.2 Consent of KPMG LLP (included in Part II of Registration Statement).
23.3 Consent of Wright & Company, Inc. (included in Part II of Registration
Statement).
[Comment1]Letterhead should be used on first page of this document
??
