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 such allocation would create or increase a deficit in his or her capital account (adjusted for certain liabilities, as provided in the limited partnership agreement).

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. The ability of the Partnerships 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 such 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 such would create or increase a deficit in that Partner's capital account.

For a fuller discussion of capital accounts and tax allocations, see "Tax Considerations - Partnership Allocations."

Upon 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 such deficit; however, no Investor Partner will be obligated to restore his or her deficit, if any.

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 such allocations to be recognized for federal income tax purposes either because of the promulgation of Treasury Regulations or other developments in the tax law. Any new allocation provisions provided by an amendment must be made in a manner that would result in the most favorable aggregate consequences to the Investor Partners as nearly as possible consistent with the original allocations described herein. See Section 11.09 of the 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:

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.

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 such 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 such prospects (see "Proposed Activities - Acquisition of Prospects").

Each Partnership 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 such 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 the foregoing 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 such 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."

The Partnerships 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 RNG. 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 such sales commissions and due diligence and marketing support expenses in whole or in part to NASD licensed broker-dealers for sale of the Units, reimbursement of due diligence and marketing support expenses, and other compensation, but will retain the wholesaling fees of $7,500 ranging to $750,000.

PROPOSED ACTIVITIES

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 Program 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 flow from the sale of natural gas produced by successful wells commencing approximately six months after each partnership closes, and continuing 20 years or more.

- A diversified investment in ten or more wells to reduce the negative impact of unsuccessful or substandard wells.

- Tax deductions in the year of investment equal to 87-89.5% of your investment.

- Accurate and timely reports, including Form K-1 tax information distributed the first week of February.

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 such prospects, the level of natural gas prices in the future, the degree of governmental regulation over the production and sale of natural gas, the future economic conditions in the United States (and the world), and changes in the Internal Revenue Code. Accordingly, 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 (i) for the drilling and completion of Partnership wells and (ii) for the subsequent supervision of field operations with respect to each producing well.

Each Partnership will invest in a number of prospects, either by itself or in conjunction with other parties, consistent with the objective of maintaining a meaningful interest in the wells to be drilled. The Partnerships will not acquire any interest in currently or formerly producing gas wells. Most wells to be drilled by the Partnerships will be direct offsets to producing wells ("proved undeveloped prospects"). Therefore, it is unlikely that a well on a prospect will have the effect of proving up any additional acreage outside of the prospect. For this reason, the Partnerships are expected to acquire only spacing units on which wells are to be drilled without also acquiring any surrounding acreage. Nevertheless, if drilling on a Partnership prospect proves up an adjoining spacing unit owned by 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 such spacing unit.

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 therein, upon which drilling operations may be conducted.

Depending on its attributes, a prospect may be characterized as an "exploratory" or "development" site. Generally speaking, exploratory drilling involves the conduct of drilling operations in search of a new and yet undiscovered pool of oil and gas (or, alternatively, drilling within a discovered pool with the hope of greatly extending the limits of such pool), whereas development drilling involves drilling to a known producing formation in a previously discovered field.

The Partnership intends to conduct development drilling operations in one or more of the following areas: North Central West Virginia to develop Benson, Riley and other shallow Upper Devonian and Mississippian Formations; Southern West Virginia to develop Ravencliff through Gordon Formations as well as the Devonian Shale; Southern and Central Pennsylvania to develop Upper Mississippian through Upper Devonian Reservoirs; western Pennsylvania to develop the Medina and Whirlpool reservoirs; Michigan to develop the Antrim Formation; and 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 such other formations as we may, in our sole and absolute discretion, deem advisable, provided that such 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.

The Partnerships will acquire prospects under arrangements whereby the Partnership will acquire up to 100% of the working interest, subject to landowners' royalty interests and other royalty interests payable to unaffiliated third parties in varying amounts, provided that the weighted average of such royalty interests for all prospects of a particular Partnership will not exceed 20%. In 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 certain conditions for the treatment of Additional General Partners' interests in the Partnership as not passive activities (and thereby not subjecting the Additional General Partners to limitation on the deduction of Partnership losses attributable to such Additional General Partners to income from passive activities), 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 such prospects and participate in the drilling and development of the prospect on the same basis as the Partnerships.

In acquiring interests in leases, the Partnerships may pay such consideration and make such contractual commitments and agreements as 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, 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 such property in which case the price will not exceed the fair market value of such 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 Federal and state departments or agencies, agreements with other working interest owners in the prospects, farm-ins, and continuing review of other prospects that may be available.

- 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, such 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 such 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.

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 such other information as may be available and useful. The stratigraphic nature of the prospects in the areas currently being developed is best evaluated by subsurface mapping based on data from surrounding wells. As a result, nearly all wells drilled by the Partnership will be direct offsets to existing producing wells. 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.

In addition, we expect to acquire additional acreage on an ongoing basis throughout 2001 and beyond for the Program 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 Program 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 Program.

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.

Colorado. Wattenberg Field, located north and east of Denver, Colorado, is the most prolific field 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. This Basin has produced more than 2.3 trillion cubic feet of natural gas and over 900 million barrels of oil since 1902, making it the most prolific area in Colorado.

We expect our Piceance Basin wells to produce natural gas along with very small quantities of oil and water. The producing interval has numerous stacked sandstone zones that have made dry hole rates in the area very low.

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 Program Partnerships 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. The Green River Basin in southwestern Wyoming and northwestern Colorado has an estimated 125 TCF of remaining recoverable gas reserves in predominantly 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:

- 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.

- The General 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 such 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 such prospects will select the operator for the wells drilled on such 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 such 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 such 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 RNG 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, such as the quality of the gas, well pressure, estimated reserves, prevailing supply conditions and any applicable price regulations promulgated by the Federal Energy Regulatory Commission. The Partnership expects to sell oil discovered and sold by it at free market prices. See "Competition, Markets and Regulation."

Drilling and Operating Agreement.

- On wells where the Managing General Partner is operator, it will have full control over the Partnerships' wells.

- 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 (which we refer to in this section as the "Agreement") with us as operator. The Agreement (filed as Exhibit 10(a) to the Registration Statement) provides that the operator will conduct and direct and have full control of all operations on the Partnership's prospects. The operator will have no liability as operator to the Partnership for losses sustained or liabilities incurred, except as may result from the operator's negligence or misconduct. Under the terms of the Agreement, we may subcontract certain of those 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 such a joint venture is proportional to its contribution to the total cost of such venture.

It is anticipated that the Partnerships, PDC, and other third party joint venturers will share the cost of the Michigan Antrim projects. The 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 such party. If any party fails or is unable to pay its share of expense within 60 days after rendering a statement therefor by us, we will pay the unpaid amount in the proportion that the interest of each such party bears to the interest of all such parties.

In the event not all participants in a well wish to participate in a completion attempt, the parties desiring to do so may pay all costs of the completion attempt including the cost of necessary well equipment and a gathering pipeline, and such parties will receive all income and pay all operating costs from the well until they have received an amount equal to 300% of the completion and connection costs, after which time the non-consenting parties will have the right to receive their original interest in further revenues and expenses.

The operator is obligated to commence drilling the wells on each prospect within 180 days of the date of the funding of the Partnership, but in no case later than March 31, 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 such 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 Agreement will not refund any portion of amounts paid in the event actual costs are less than amounts paid but will apply any such amounts solely for payment of additional drilling services to the Partnership. If the operator determines that the well is not likely to produce oil and/or gas in commercial quantities, the operator will plug and abandon the well in accordance with applicable regulations.

Each Partnership will bear its proportionate share of the cost of drilling and completing or drilling and abandoning wells, where we serve as operator as follows:

1. The cost of the prospect; and

2) For intangible well costs:

1. 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

2. 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.

FOOTAGE BASED RATES

* The depth used for determining well charges will be the deepest penetration by the drilling bit.

In the event the foregoing rates exceed competitive rates available from other non-affiliated persons in the area engaged in the business of rendering or providing comparable services or equipment, we will adjust the foregoing rates to an amount equal to that competitive rate.

The Agreement provides that the Partnership will pay the operator the prospect cost and the dry hole cost for each planned well prior to the spud date, and the balance of the completed well costs when the well is completed and ready for production, in the case of a completed well.

The operator will provide all necessary labor, vehicles, supervision, management, accounting, and overhead services for normal production operations, and will deduct from Partnership revenues a monthly charge 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.

* Northern West Virginia, Southern West Virginia, Pennsylvania

** Does not include the monthly charge for operation of the compression, water disposal, gas injection, and other facilities.

The Partnership will have the right to take in kind and separately dispose of its share of all oil and gas produced from its prospects, excluding its proportionate share of production required for lease operations and production unavoidably lost. Initially the Partnership will designate the operator as its agent to market such production and authorize the operator to enter into and bind the Partnership in such agreements as it deems in the best interest of the Partnership for the sale of such oil and/or gas. If pipelines which have been built by 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 Agreement, multiplied by the ratio of the then current average weekly earnings of Crude Petroleum and Gas Production workers to the average weekly earnings of Crude Petroleum and Gas Production workers for 1999, as published by the United States Department of Labor, Bureau of Labor Statistics, provided that the charge may not exceed the rate which would be charged by the comparable operators in the area of operations.

The Agreement will continue in force so long as any such well or wells produce, or are capable of production, and for an additional period of 180 days from cessation of all production.

- The Partnership will sell the produced gas to industrial users, gas brokers, interstate pipelines, or local utilities, subject to market sensitive contracts whereby the price of gas sold will vary as a result of market forces.

- The Partnership 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 whereby 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 certain 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 certain 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 RNG to market gas, enter into hedges or swaps, or purchase options on behalf of the Partnership. RNG 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.

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 such interest of gross revenues derived from the wells. For the purpose of this chart, "gross revenues" is defined as the "Well Head Gas Price" paid by the gas purchaser. In the event the Partnership acquires less than a 100% working interest, the percentages available to the Partnership will decrease proportionately.

Program Revenue Sharing

- 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 such insurance may not be sufficient to cover all liabilities. Each Unit held by the Additional General Partners represents an open-ended security for unforeseen events such as blowouts, lost circulation, stuck drillpipe, etc. which may result in unanticipated additional liability materially in excess of the per Unit subscription amount.

We have obtained various insurance policies, as described below, and intend to maintain such 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;

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 such 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 such Partnerships 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 such two-times insurance coverage during such 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 such 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 such insurance to the Partnership is estimated to be approximately $625 per well in the year that it is drilled (plus blowout insurance for Colorado wells of approximately $2,000 per well) and approximately $140 per each producing well for the Partnership liability and other insurance coverages. The costs of insurance are allocated based primarily upon the level of natural gas operations. Insurance premiums may increase in the future. The primary effect of increasing premiums cost is to reduce funds otherwise available for Partnership drilling operations or for distribution to investors.

We will notify all Additional General Partners at least 30 days prior to any material change in the amount of such insurance coverage. Within this 30-day period and otherwise after the expiration of one year following the closing of the offering with respect to a particular Partnership, Additional General Partners have the right to convert their Units into Units of limited partnership interest by giving written notice to 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 such amendment with the State of West Virginia prior to the effective date of the change in insurance coverage and thereby effectuate the conversion of the interest of the former Additional General Partner to that of a Limited Partner.

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 (the "Roll-Up Entity") and the issuance of securities by the Roll-Up Entity to Investor Partners in cases where there is also a significant adverse change in the voting rights of the 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 Roll-Up should occur in the future. These policies include:

COMPETITION, MARKETS AND REGULATION

Competition is keen among persons and companies involved in the exploration for and production of oil and gas. The Partnership will encounter strong competition at every phase of its business including acquiring properties suitable for exploration and development and marketing of oil and gas. It will compete with entities having financial resources and staffs substantially larger than those available to the Partnership. There are thousands of oil and gas companies in the United States. The national supply of natural gas is widely diversified, with no one entity controlling over 5%. As a result of this competition and Federal Energy Regulatory Commission ("FERC") and Congressional deregulation of gas prices, prices are generally determined by competitive forces.

There will also be competition among operators for drilling equipment, tubular goods, and drilling crews. Such competition may affect the ability of each Partnership to acquire leases suitable for development by the Partnerships and to develop expeditiously such leases once they are acquired.

The marketing of any oil and gas produced by 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 certain U.S. markets. Such imports could have an adverse effect on both the price and volume of gas sales from Partnership wells.

FERC Order No. 636, issued in 1992, requires pipelines to separate their storage, sales and transportation functions and 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. Such increases in demand, should they materialize, will come from a number of sources, including as boiler fuel to meet increase electric power generation needs and as an industrial fuel that is environmentally preferable to alternatives such as nuclear power and coal.

The accelerating deregulation of natural gas and electricity transmission has caused, and will continue to cause, a convergence of the gas and electric industries. CNG Transmission, which has purchased Partnership production in the past, is an example of 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. 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, thereby 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 such legislation is directed toward decreasing demand or increasing supply.

Members of the Organization of Petroleum Exporting Countries establish prices and production quotas for petroleum products from time to time, with the intent of reducing the current global oversupply and maintaining or increasing certain price levels. 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 certain quality standards and that a tariff be paid for quantities transported.

The Partnership expects to sell gas from its wells to Hope Gas, Equitable Gas, and other local distribution companies ("LDCs"), or on the spot market via open access transportation arrangements through CNG Transmission, Hope Gas, Eastern American Energy, MichCon, Colorado Interstate Gas, Equitrans or other pipelines. 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, LDCs must take an increasingly active role in acquiring their own gas supplies. Consequently, pipelines and LDCs are buying gas directly from gas producers and marketers, and retail unbundling efforts are causing many end-users to buy their own reserves. Activity by state regulatory commissions to review LDC procurement practices more carefully and to unbundle retail sales from transportation has caused gas purchasers to minimize their risks in acquiring and attaching gas supply and has added to competition in the natural gas marketplace.

In Order No. 587 and other initiatives, FERC required pipelines to develop electronic 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.

- 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, pursuant to the Wellhead Decontrol Act of 1989, FERC may not regulate the price of gas. Deregulated gas production may be sold at market prices determined by supply, demand, Btu content, pressure, location of wells, and other factors.

Federal and state regulations will affect production of Partnership oil and gas. In most areas of operations the production of oil is regulated by conservation laws and regulations, which set allowable rates of production and otherwise control the conduct of oil operations.

The Partnership's drilling and production operations will also be subject to environmental protection regulations established by Federal, state, and local agencies, which in turn may necessitate significant capital outlays which would materially affect the financial position and business operations of the Partnership (see "Risk Factors - Environmental Hazards and Liabilities").

Certain states control production through regulations establishing the spacing of wells, limiting the number of days in a given month during which a well can produce and otherwise limiting the rate of allowable production. Through regulations enacted to protect against waste, conserve natural resources and prevent pollution, local, state and Federal environmental controls will also affect Partnership operations. Such regulations could affect Partnership operations and could necessitate spending funds on environmental protection measures, rather than on drilling operations. If any penalties or prohibitions were imposed on a Partnership for violating such regulations, that Partnership's operations could be adversely affected.

In prior programs, expenses associated with compliance with environmental regulations have represented approximately 10-15% of the cost of drilling and completing wells, and it is expected that similar costs will be incurred in this program. These costs are included in the footage-based rates described at "Proposed Activities - Drilling and Operating Agreement," above.

Various legislative proposals in Congress and in state legislatures could, if enacted, affect the petroleum and natural gas industries. Such proposals involve, among other things, imposition of direct or indirect price limitations on natural gas production, imposition of land use controls (such as prohibiting drilling activities on certain Federal and state lands in roadless wilderness areas) and other measures. At the present time, it is impossible to predict what proposals, if any, will actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals will have on the Partnerships' operations.

MANAGEMENT

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 such time and talents to such 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' gas wells.

PDC (the "Company" or the "Managing General Partner") will act as driller/operator for the Program wells. Since 1969 the Company has drilled over 2,000 wells in West Virginia, Tennessee, Ohio, Michigan, Colorado and Pennsylvania. The Company currently operates approximately 2,250 wells.

The Company employs four geologists who develop prospects for drilling by the Company and who help oversee the drilling process. In addition, the Company has an engineering staff of four who are responsible for well completions, pipelines, and production operations. The Company retains drilling subcontractors, completion subcontractors, and a variety of other subcontractors in the performance of the work of drilling contract wells. In addition to technical management, the Company may provide services, at competitive rates, from Company-owned service rigs, a water truck, frac tanks, roustabouts, and other assorted small equipment. The Company may lay short gathering lines, or may subcontract all or part of the work where it is more cost effective for a partnership. The Company employs full-time welltenders and supervisors to operate its wells. In addition, the engineering staff evaluates reserves of all wells at least annually and reviews well performance against expectations. All services provided by us are provided at rates less than or equal to prevailing rates for similar services provided by unaffiliated persons in the area.

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:

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

James N. Ryan has served as President and Director of PDC from 1969 to 1983 and was elected Chairman and Chief Executive Officer in March 1983.

Steven R. Williams has served as President and Director of PDC since March 1983. Prior to joining the Company, Mr. Williams was employed by Exxon until 1979 and attended Stanford Graduate School of Business, graduating in 1981. He then worked with Texas Oil and Gas until July 1982, when he joined Exco Enterprises, an oil and gas investment company, as manager of operations.

Dale G. Rettinger has served as Vice President and Treasurer of PDC since July 1980, and was appointed Chief Financial Officer in September 1997. Mr. Rettinger was elected Director in 1985. Previously, Mr. Rettinger was a partner with Main Hurdman, Certified Public Accountants, having served in that capacity since 1976.

Roger J. Morgan has been a member of the law firm of Young, Morgan & Cann, Clarksburg, West Virginia, for more than the past five years. Mr. Morgan is not active in the day-to-day business of PDC, but his law firm provides legal services to PDC.

Vincent F. D'Annunzio has for the past five years served as president of Beverage Distributors, Inc., located in Clarksburg, West Virginia. Mr. D'Annunzio is a director of West Union Bank, West Union, West Virginia.

Jeffrey C. Swoveland has been Director of Finance with Equitable Resources, Inc. since September 1994. Prior thereto, he was a lending officer with Mellon Bank N.A. since July 1989. Mr. Swoveland was Senior Planning Analyst with Consolidated Natural Gas in 1988 and 1989. Mr. Swoveland received an MS degree in finance from Carnegie Mellon University.

Donald B. Nestor was elected as a director in March 2000, is a Certified Public Accountant and a Partner in the CPA firm of Toothman, Rice, P.L.L.C. and is in charge of the firm's Buckhannon, West Virginia office. Mr. Nestor has served in that capacity for more than the past five years.

Thomas Riley has served as Vice President - Gas Marketing and Acquisitions of PDC since April 1996. Prior to joining PDC, Mr. Riley was president of Riley Natural Gas Company ("RNG"), a natural gas marketing company, from its inception in 1987. PDC acquired RNG 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.

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.

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

* Less than 1%

None of our officers or directors will receive any direct remuneration or other compensation from the Partnerships. Such persons will receive compensation solely from PDC. Information as to compensation paid by us to our directors and executive officers may be obtained from publicly available reports filed by us with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934.

We as driller/operator are subject to certain minor legal proceedings arising from the normal course of business. Such legal actions are not considered material to the operations of the Partnership or us.

CONFLICTS OF INTEREST

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 such 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, such conflicts nevertheless may occur and, in such event, our actions may not be most advantageous to the Partnership and could fall short of the full exercise of such 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 such 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. Such 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 such proceeding.

Due Diligence Review. PDC Securities Incorporated, the Dealer Manager 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 such agreement. See "Transactions with the Managing General Partner or Affiliates Thereof," 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 such 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 such additional programs. In resolving any such conflicts, each Partnership will be treated equitably with such other partnerships on a basis consistent with the funds available to the partnerships and the time limitations on the investment of funds. However, no provision has been made for an independent review of conflicts of interest. 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, in the event more than one Partnership has funds available for drilling, the Partnerships will alternate drilling of wells based on the "best available prospect" format. The determination of the "best available prospect" is based on 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 such 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 such acquisition can be made from the capital contributions. In the event such property is not acquired by the Partnership, the Partnership may lose a promising prospect. Except as otherwise provided by the limited partnership agreement, such 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 therein to transfer to the Partnership. This may result in another drilling program sponsored by us acquiring property adjacent to Partnership property. Such other program could gain an advantage over the Partnership by reason of the knowledge gained through the Partnership's prior experience in the area or if such other drilling program were the first to discover or develop a productive pool of oil or natural gas.

Acquisition of Prospects. 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 such leases. Certain of such 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 such prospect acquisition, we or such affiliate will offer an equivalent interest therein to the Partnership; and, if cash or financing is not available to such Partnership to enable it to consummate a purchase of an equivalent interest in such property, neither we nor any of our affiliates will acquire such 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. The Partnerships will not acquire any lease for the purpose of a subsequent sale or farmout unless the acquisition is made after a well has been drilled to a depth sufficient to indicate that such an acquisition would be in the Partnerships' best interest. 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) a Partnership lacks sufficient funds to drill on the lease and cannot obtain suitable alternative financing; (b) downgrading subsequent to a Partnership's acquisition has rendered drilling undesirable; (c) drilling would concentrate excessive funds in one location creating undue risk to a Partnership; or (d) the best interests of a Partnership, based on the standard of a prudent operator, would be served by such disposition. In the event of a farmout, we will retain for the Partnerships such 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 such 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 such 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 such person is engaged, independently of the Partnership and as an ordinary and ongoing business, in the business of rendering such services or selling or leasing such equipment and supplies to a substantial extent to other persons in the gas industry in addition to partnerships in which we or our affiliate has an interest, or, if such person is not engaged in such a business then such compensation, price or rental will be the cost of such services, equipment or supplies to such person or the competitive rate which could be obtained in the area, whichever is less. Notwithstanding any provision to the contrary, 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 Repurchase Program (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 Units, 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

[insert]

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.

As of June 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 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 -- --

____________________

FIDUCIARY RESPONSIBILITY OF 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 such losses from a general partner where the losses result from a violation by the general partner of the antifraud provisions of the Federal securities laws. The burden of proving such a breach, and all or a portion of the expense of such lawsuit, would have to be borne by the limited partner bringing such action. In the event of a lawsuit for a breach of its fiduciary duty to the Partnership and/or the Investor Partners, 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 such course of conduct was in the best interests of the Partnership and such course of conduct did not constitute negligence or misconduct of the Managing General Partner. 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) such claims have been dismissed with prejudice on the merits by a court of competent jurisdiction or (3) a court of competent jurisdiction approves a settlement of such claims against a particular indemnitee and finds that indemnification of the settlement and the related costs should be made, and the court considering the request for indemnification has been advised of the position of the Securities and Exchange Commission and of the position of any state securities regulatory authority in which securities of the Partnership were offered or sold as to indemnification for violations of securities laws; provided, however, the court need only be advised of the positions of the securities regulatory authorities of those states (i) which are specifically set forth in the prospectus and (ii) in which plaintiffs claim they were offered or sold Partnership Units. A successful claim for indemnification would deplete Partnership assets by the amount paid. As a result of such indemnification provisions, a purchaser of Units may have a more limited right of legal action than he would have if such provision were not included in the limited partnership agreement. To the extent that the indemnification provisions purport to include indemnification for liabilities arising under the Securities Act of 1933 (the "Securities Act"), in the opinion of the Securities and Exchange Commission, such indemnification is against public policy as expressed in the Securities Act, and is, therefore, unenforceable.

The 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 such party is prohibited from being indemnified.

PRIOR ACTIVITIES

Petroleum Development Corporation ("PDC"), as general partner, has previously sponsored ten private and nine public drilling programs. PDC 2003 Drilling Program (the "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.

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 11/97 208.85 20,000 4,166,946 --

PDC 1997-B 9/97 3/98 337.97 20,000 6,759,470 --

PDC 1997-C 11/97 5/98 302.16 20,000 6,043,257 --

PDC 1997-D 12/97 6/98 925.98 20,000 18,519,579 --

PDC 1998-A 6/98 12/98 263.61 20,000 5,272,135 --

PDC 1998-B 9/98 3/99 357.25 20,000 7,145,101 --

PDC 1998-C 11/98 5/99 390.64 20,000 7,812,783 --

PDC 1998-D 12/98 7/99 1,026.26 20,000 20,525,261 --

PDC 1999-A 5/99 11/99 240.08 20,000 4,800,739 --

PDC 1999-B 9/99 3/00 278.00 20,000 5,539,893 --

PDC 1999-C 11/99 5/00 354.38 20,000 7,087,559 --

PDC 1999-D 12/99 7/00(2) 935.47 20,000 18,709,342 --

PDC 2000-A 5/00 11/00(3) 247.84 20,000 4,956,718 --

______________

Productive Well Table

June 30, 2000

Gross Wells(1) Net Wells(2)

Partnership Oil Gas Dry Oil Gas Dry

Pennwest

Petroleum

Group 1984 27 13 - 27 5.5 -

Pennwest

Petroleum

Group 1985-A 14 13 1 14 7.8 .6

Petrowest

Gas Group

1986-A - 8 2 - 5.4 1.0

Petrowest

Gas Group

1987 - 9 1(3) - 7.1 .1(3)

Petrowest

Gas Group

- 9 1 - 5.5 .6

PDC 1987 - 7 - - 2.6 -

PDC 1988 - 5 1 - 4.1 .8

PDC 1988-B - 5 - - 4.7 -

PDC 1988-C - 9 1 - 7.0 .8

PDC 1989-P - 8 1 - 7.8 .9

PDC 1989-A - 6 1 - 5.5 .9

PDC 1989-B - 19 2 - 17.0 1.8

PDC 1990-A - 7 1 - 6.0 .9

PDC 1990-B - 11 - - 10.3 -

PDC 1990-C - 15 2 - 14.4 2.0

PDC 1990-D - 16 1 - 15.8 1.0

PDC 1991-A - 13 - - 12.0 -

PDC 1991-B - 8 2 - 7.2 2.0

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

Total ...... 41 1,140 92 41 926.48 80.2

_____________________

Participants' Net Cash Table

June 30, 2000

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- June June 30, June 30, June 30,

Costs(2) 30, 2000 2000 2000

Pennwest Petroleum

Group 1984 $2,093,125 $2,462,500 $1,381,829 $ 537 $1,312,327 $ 537 $532,312

Pennwest Petroleum

Group 1985-A 1,976,250 2,325,000 1,013,189 4,089 969,917 4,089 645,096

Petrowest Gas

Group 1986-A 956,250 1,125,000 592,251 618 565,481 618 463,176

Petrowest Gas

Group 1987 1,143,250 1,345,000 961,518 2,723 918,898 2,723 522,516

Petrowest Gas

Group 1987-B 983,875 1,157,500 453,876 817 427,506 817 365,481

PDC 1987 454,750 535,000 333,243 1,001 315,671 1,001 234,743

PDC 1988 770,100 906,000 745,155 2,500 708,266 2,500 478,511

PDC 1988-B 841,500 990,000 285,473 802 261,633 802 262,192

PDC 1988-C 1,326,000 1,560,000 632,363 5,620 589,307 5,620 497,399

PDC 1989-P 1,523,625 1,792,500 1,163,606 7,600 1,085,721 7,600 783,330

PDC 1989-A 1,028,500 1,210,000 857,267 13,736 814,183 13,736 542,002

PDC 1989-B 3,153,500 3,710,000 1,688,021 8,188 1,582,385 8,188 771,487

PDC 1990-A 1,195,100 1,406,000 422,098 1,631 361,885 1,631 141,099

PDC 1990-B 1,887,850 2,221,000 967,692 4,286 929,932 4,286 625,949

PDC 1990-C 2,956,300 3,478,000 1,374,129 18,827 1,304,891 18,827 638,331

PDC 1990-D 3,132,674 3,685,500 1,420,445 17,459 1,359,578 17,459 825,534

PDC 1991-A 2,328,150 2,739,000 1,395,628 9,364 1,292,163 9,364 849,746

PDC 1991-B 1,583,975 1,863,500 779,231 10,732 750,356 10,732 494,726

PDC 1991-C 2,325,600 2,736,000 1,204,665 13,633 1,118,065 13,633 752,869

PDC 1991-D 4,469,725 5,258,500 1,491,226 19,174 1,418,214 19,174 968,826

PDC 1992-A 2,472,396 2,908,700 517,823 3,846 439,099 3,846 378,183

PDC 1992-B 2,532,246 2,979,100 1,479,347 25,833 1,418,290 25,833 893,164

PDC 1992-C 5,430,563 6,388,900 3,822,651 65,144 3,700,537 65,144 1,740,286

PDC 1993-A 2,647,750 3,026,000 2,919,331 24,931 2,725,155 24,931 129,599

PDC 1993-B 2,130,620 2,435,000 835,942 12,228 777,035 12,228 --

PDC 1993-C 2,665,865 3,046,700 819,373 14,288 762,987 14,288 --

PDC 1993-D 2,545,375 2,909,000 1,012,962 22,274 971,724 22,274 --

PDC 1993-E 6,438,950 7,358,800 2,939,909 43,665 2,790,961 43,665 --

PDC 1994-A 1,798,563 2,055,500 488,943 6,785 448,973 6,785 --

PDC 1994-B 2,353,579 2,689,804 945,273 24,190 890,015 24,190 --

PDC 1994-C 2,052,636 2,345,870 688,714 16,519 632,277 16,519 --

PDC 1994-D 6,605,166 7,548,761 2,313,200 58,066 2,126,345 58,066 --

PDC 1995-A 1,282,403 1,465,603 534,519 10,611 486,460 10,611 --

PDC 1995-B 1,625,442 1,857,648 386,545 5,487 330,537 5,487 --

PDC 1995-C 1,850,184 2,114,496 426,773 6,877 369,976 6,877 --

PDC 1995-D 7,137,437 8,157,071 1,991,056 54,939 1,780,360 54,939 --

PDC 1996-A 2,241,294 2,576,200 1,168,045 30,334 1,033,227 30,334 --

PDC 1996-B 2,335,695 2,684,707 868,361 37,434 743,445 37,434 --

PDC 1996-C 3,433,436 3,946,478 952,079 62,094 834,804 62,094 --

PDC 1996-D 13,312,502 15,301,726 3,204,517 124,315 2,846,427 124,315 --

PDC 1997-A 3,625,243 4,166,946 826,112 32,626 732,191 32,626 --

PDC 1997-B 5,880,739 6,759,470 1,053,997 37,825 904,596 37,825 --

PDC 1997-C 5,257,634 6,043,257 1,230,218 83,402 908,307 83,402 --

PDC 1997-D 16,112,034 18,519,579 1,711,180 144,460 1,327,295 144,460 --

PDC 1998-A 4,586,758 5,272,135 702,735 103,348 551,708 103,348 --

PDC 1998-B 6,216,237 7,145,101 869,260 196,305 775,862 196,305 --

PDC 1998-C 6,797,121 7,812,783 900,645 140,418 634,988 140,418 --

PDC 1998-D 17,856,977 20,525,261 1,422,337 269,398 960,773 269,398 --

PDC 1999-A 4,176,643 4,800,739 390,067 118,924 250,478 118,924 --

PDC 1999-B 4,819,707 5,539,893 510,602 221,388 323,398 221,388 --

PDC 1999-C 6,166,176 7,087,559 371,920 130,598 130,598 130,598 --

PDC 1999-D(6) 16,277,127 18,709,342 187,303 -- -- -- --

PDC 2000-A(7) 4,312,345 4,956,718 -- -- -- -- --

_____________________

Managing General Partner's Payout Table

June 30, 2000

Revenues Before Deducting

Total Expenditures Operating Costs(2)

Including Total As of During Three Months

Partnership Operating Costs(1) June 30, 2000 Ended June 30, 2000

Pennwest Petroleum

Group 1984 $ 160,923 $275,156 $ 1,704

Pennwest Petroleum

Group 1985-A 150,586 233,957 3,181

Petrowest Gas

Group 1986-A 81,189 161,548 1,662

Petrowest Gas

Group 1987 98,614 230,288 2,297

Petrowest Gas

Group 1987-B 77,962 120,511 1,168

PDC 1987 38,244 82,024 810

PDC 1988 67,141 181,298 1,679

PDC 1988-B 67,827 96,475 1,220

PDC 1988-C 109,626 180,858 2,466

PDC 1989-P 124,591 272,283 3,220

PDC 1989-A 223,294 324,564 5,834

PDC 1989-B 560,152 627,099 6,534

PDC 1990-A 197,644 163,210 1,889

PDC 1990-B 345,459 371,383 5,713

PDC 1990-C 523,895 520,926 10,177

PDC 1990-D 531,708 504,821 9,514

PDC 1991-A 408,071 493,547 7,019

PDC 1991-B 260,344 278,496 4,668

PDC 1991-C 395,843 433,375 7,827

PDC 1991-D 710,289 566,367 12,241

PDC 1992-A 296,250 85,543 -0-

PDC 1992-B 425,874 514,690 11,078

PDC 1992-C 918,057 1,235,711 27,264

PDC 1993-A 495,233 849,565 10,941

PDC 1993-B 320,566 264,700 6,096

PDC 1993-C 392,924 251,627 7,921

PDC 1993-D 364,401 281,124 8,331

PDC 1993-E 812,959 701,561 18,925

PDC 1994-A 539,085 206,748 4,605

PDC 1994-B 680,509 322,821 9,883

PDC 1994-C 589,453 248,139 7,687

PDC 1994-D 1,877,605 789,103 25,197

PDC 1995-A 379,316 187,988 4,999

PDC 1995-B 443,693 127,160 3,358

PDC 1995-C 521,719 160,760 5,083

PDC 1995-D 1,966,661 654,670 22,893

PDC 1996-A 661,759 365,225 12,752

PDC 1996-B 689,844 274,218 10,907

PDC 1996-C 1,008,064 291,944 17,198

PDC 1996-D 3,891,042 1,028,012 57,845

PDC 1997-A 1,019,792 248,589 13,910

PDC 1997-B 1,659,685 325,519 19,541

PDC 1997-C 1,480,956 399,140 32,859

PDC 1997-D 4,378,471 666,843 76,381

PDC 1998-A 1,220,916 249,909 40,660

PDC 1998-B 1,638,900 302,154 67,716

PDC 1998-C 1,799,727 325,606 59,453

PDC 1998-D 4,620,942 512,280 115,260

PDC 1999-A 1,071,457 124,812 40,717

PDC 1999-B 1,243,118 165,841 70,685

PDC 1999-C 1,575,287 126,722 40,281

PDC 1999-D(3) 4,079,995 57,539 -

PDC 2000-A(4) 1,078,086 - -

_____________________

Managing General Partner's Net Cash Table

June 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 June June As of June Ended June Credits

Partnership Costs 30, 2000 30, 2000 30, 2000 30, 2000 (4)

Pennwest

Petroleum

Group 1984 $ 129,605 $243,838 $ 1,460 $240,180 $ 1,460 $28,016

Pennwest

Petroleum

Group 1985-A 122,368 205,738 2,875 203,461 2,875 33,952

Petrowest

Gas Group

1986-A 59,210 139,569 1,181 135,129 1,181 24,378

Petrowest

Gas Group

1987 70,789 202,464 1,712 196,252 1,712 27,501

Petrowest

Gas Group

1987-B 60,921 103,470 844 99,095 844 19,236

PDC 1987 28,158 71,938 610 69,294 610 12,355

PDC 1988 47,684 161,841 1,290 156,292 1,290 25,185

PDC 1988-B 52,105 80,754 888 76,147 888 13,800

PDC 1988-C 82,105 153,337 1,986 146,020 1,986 26,179

PDC 1989-P 94,342 242,033 2,600 228,645 2,600 41,228

PDC 1989-A 114,278 215,548 3,434 204,777 3,434 135,500

PDC 1989-B 350,389 417,336 2,047 390,927 2,047 192,872

PDC 1990-A 132,789 98,354 408 83,301 408 35,275

PDC 1990-B 209,761 235,685 1,071 226,245 1,071 156,487

PDC 1990-C 328,478 325,508 4,707 308,198 4,707 159,583

PDC 1990-D 348,075 321,187 4,365 305,970 4,365 206,383

PDC 1991-A 258,683 344,159 2,341 318,293 2,341 212,436

PDC 1991-B 175,997 194,149 2,683 188,374 2,683 123,681

PDC 1991-C 258,400 295,932 3,408 274,282 3,408 188,217

PDC 1991-D 496,639 352,717 4,793 334,464 4,793 242,207

PDC 1992-A 274,711 64,004 -0- 44,323 -0- -0-

PDC 1992-B 281,361 370,177 6,458 357,966 6,458 223,291

PDC 1992-C 603,396 921,050 16,286 896,628 16,286 435,072

PDC 1993-A 294,194 648,526 5,473 605,902 5,473 29,160

PDC 1993-B 236,736 180,870 2,684 167,939 2,684 --

PDC 1993-C 296,207 154,910 3,136 142,533 3,136 --

PDC 1993-D 282,819 199,542 4,889 190,490 4,889 --

PDC 1993-E 715,438 604,041 9,585 571,345 9,585 --

PDC 1994-A 449,641 117,304 1,696 108,530 1,696 --

PDC 1994-B 588,395 230,707 6,047 216,892 6,047 --

PDC 1994-C 513,159 171,845 4,130 157,736 4,130 --

PDC 1994-D 1,651,292 562,790 14,423 516,076 14,423 --

PDC 1995-A 320,601 129,273 2,645 117,258 2,645 --

PDC 1995-B 406,361 89,827 1,394 75,825 1,394 --

PDC 1995-C 462,546 101,587 1,713 87,388 1,713 --

PDC 1995-D 1,784,359 472,368 12,116 419,694 12,116 --

PDC 1996-A 560,324 263,790 7,584 230,086 7,584 --

PDC 1996-B 583,924 168,297 (4,990) 137,068 (4,990) --

PDC 1996-C 858,359 142,239 (7,487) 112,920 (7,487) --

PDC 1996-D 3,328,126 465,097 31,078 375,575 31,078 --

PDC 1997-A 906,311 135,108 8,156 111,628 8,156 --

PDC 1997-B 1,470,185 136,019 9,456 98,669 9,456 --

PDC 1997-C 1,314,409 232,593 20,850 152,115 20,850 --

PDC 1997-D 4,028,009 316,382 36,114 220,411 36,114 --

PDC 1998-A 1,146,758 175,683 25,837 137,926 25,837 --

PDC 1998-B 1,554,059 217,313 49,076 193,964 49,076 --

PDC 1998-C 1,699,280 225,160 35,104 158,746 35,104 --

PDC 1998-D 4,464,244 355,582 67,349 240,191 67,349 --

PDC 1999-A 1,044,161 97,516 29,731 62,619 29,731 --

PDC 1999-B 1,204,927 127,650 55,347 80,849 55,347 --

PDC 1999-C 1,541,544 92,979 32,649 32,649 32,649 --

PDC 1999-D(5) 4,069,282 46,826 -- -- -- --

PDC 2000-A(6) 1,078,086 -- -- -- -- --

_____________________

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 53.26% 21.62% 74.87% 50.51% 125.38% 15/3

*Pennwest Petroleum

1985-A 41.49% 27.75% 69.23% 49.27% 118.50% 14/4

**Petrowest Gas

Group 1986 50.01% 41.17% 91.18% 49.04% 140.22% 13/3

**Petrowest Gas

Group 1987 68.08% 38.85% 106.93% 39.70% 146.62% 12/6

**Petrowest Gas

Group 1987-B 36.85% 31.58% 68.43% 39.33% 107.75% 12/3

**PDC 1987 58.70% 43.88% 102.58% 42.29% 144.87% 12/1

**PDC 1988 77.43% 52.82% 130.25% 38.11% 168.36% 11/7

**PDC 1988-B 26.38% 26.48% 52.87% 37.18% 90.04% 11/3

**PDC 1988-C 37.55% 31.88% 69.43% 37.33% 106.76% 11/1

**PDC 1989-P 59.93% 43.70% 103.63% 35.87% 139.50% 10/7

**PDC 1989-A 66.94% 44.79% 111.73% 39.86% 151.59% 10/3

**PDC 1989-B 42.46% 20.79% 63.26% 36.75% 100.00% 10/1

**PDC 1990-A 25.74% 10.04% 35.77% 32.55% 68.32% 9/8

**PDC 1990-B 41.67% 28.18% 69.86% 35.77% 105.63% 9/6

**PDC 1990-C 37.17% 18.35% 55.52% 36.89% 92.42% 9/2

**PDC 1990-D 36.71% 22.40% 59.11% 37.63% 96.73% 9/1

**PDC 1991-A 47.04% 31.02% 78.06% 33.74% 111.80% 8/8

**PDC 1991-B 39.99% 26.55% 66.54% 34.25% 100.79% 8/5

**PDC 1991-C 40.56% 27.52% 68.07% 35.63% 103.70% 8/3

**PDC 1991-D 26.83% 18.42% 45.25% 34.20% 79.45% 8/1

**PDC 1992-A 15.10% 13.00% 28.10% 31.62% 59.72% 7/8

**PDC 1992-B 47.02% 29.98% 77.00% 36.65% 113.65% 7/6

**PDC 1992-C 56.84% 27.24% 84.08% 37.64% 121.72% 7/3

**PDC 1993-A 88.41% 4.28% 92.69% 41.23% 133.92% 7/1

**PDC 1993-B 31.64% -- 31.64% 38.06% 69.70% 6/8

**PDC 1993-C 24.84% -- 24.84% 37.60% 62.44% 6/5

**PDC 1993-D 32.81% -- 32.81% 36.74% 69.56% 6/3

**PDC 1993-E 37.44% -- 37.44% 37.80% 75.24% 6/0

**PDC 1994-A 21.22% -- 21.22% 40.46% 61.68% 5/8

**PDC 1994-B 31.97% -- 31.97% 41.99% 73.96% 5/5

**PDC 1994-C 26.40% -- 26.40% 41.61% 68.01% 5/3

**PDC 1994-D 27.18% -- 27.18% 42.02% 69.20% 5/1

**PDC 1995-A 32.09% -- 32.09% 42.84% 74.93% 4/9

**PDC 1995-B 17.21% -- 17.21% 41.33% 58.54% 4/6

**PDC 1995-C 16.94% -- 16.94% 41.41% 58.35% 4/3

**PDC 1995-D 21.58% -- 21.58% 41.52% 63.10% 4/1

**PDC 1996-A 38.81% -- 38.81% 42.37% 81.18% 3/8

**PDC 1996-B 26.00% -- 26.00% 41.35% 67.35% 3/4

**PDC 1996-C 19.47% -- 19.47% 41.02% 60.49% 3/2

**PDC 1996-D 16.86% -- 16.86% 40.89% 57.75% 3/1

**PDC 1997-A 16.38% -- 16.38% 40.30% 56.68% 2/8

**PDC 1997-B 12.09% -- 12.09% 40.27% 52.36% 2/4

**PDC 1997-C 14.09% -- 14.09% 40.79% 54.89% 2/2

**PDC 1997-D 6.74% -- 6.74% 40.15% 46.89% 2/0

**PDC 1998-A 10.44% -- 10.44% 40.33% 50.77% 1/7

**PDC 1998-B 10.80% -- 10.80% 40.53% 51.33% 1/4

**PDC 1998-C 8.08% -- 8.08% 40.20% 48.27% 1/2

**PDC 1998-D 4.66% -- 4.66% 39.72% 44.39% 1/0

**PDC 1999-A 5.22% -- 5.22% 39.28% 44.50% 0/8

*PDC 1999-B 5.84% -- 5.84% 39.29% 45.13% 0/4

*PDC 1999-C 1.84% -- 1.84% 39.13% 40.97% 0/2

*PDC 1999-D(6) 0.00% -- 0.00% 39.02% 39.02% 0/0

*PDC 2000-A(7) 0.00% -- 0.00% 39.02% 39.02% 0/0

* Program contains oil & gas production

** Program contains gas production

_____________________

Partnership Proved Reserves and Future Net Revenues

as of January 1, 2000(1)

Category of Estimated Estimated Estimated Percent Value

Partnership Proved Reserves Net Oil Net Gas Future Net Discounted

BBL Reserves Reserves Revenues at 10% Annum

PDC 1989-A(2) Proved Developed 74,289 699,530 $2,512,336 $919,538

Proved Undeveloped - -

Totals 74,289 699,530 $2,512,336 $919,538

PDC 1989-B(2) Proved Developed - 868,746 $1,088,606 $494,607

Proved Undeveloped - - - -

Totals - 868,746 $1,088,606 $494,607

PDC 1990-A(2) Proved Developed - 185,298 $166,338 $101,476

Proved Undeveloped - - - -

Totals - 185,298 $166,338 $101,476

PDC 1990-B(2) Proved Developed - 908,911 $1,527,737 $427,844

Proved Undeveloped - - - -

Totals - 908,911 $1,527,737 $427,844

PDC 1990-C(2) Proved Developed - 1,352,069 $2,138,263 $882,260

Proved Undeveloped - - - -

Totals - 1,352,069 $2,138,263 $882,260

PDC 1990-D(2) Proved Developed - 1,852,164 $3,028,473 $941,893

Proved Undeveloped - - - -

Totals - 1,852,164 $3,028,473 $941,893

PDC 1991-A(2) Proved Developed - 1,076,916 $1,591,994 $514,817

Proved Undeveloped - - - -

Totals - 1,076,916 $1,591,994 $514,817

PDC 1991-B(2) Proved Developed - 808,269 $1,404,561 $583,489

Proved Undeveloped - - - -

Totals - 808,269 $1,404,561 $583,489

PDC 1991-C(2) Proved Developed - 1,261,450 $1,909,232 $657,947

Proved Undeveloped - - - -

Totals - 1,261,450 $1,909,232 $657,947

PDC 1991-D(2) Proved Developed - 1,537,323 $2,284,487 $977,741

Proved Undeveloped - - - -

Totals - 1,537,323 $2,284,487 $977,741

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 - - - -

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 Program. All references in this "Tax Considerations" section are to the tax opinion set forth in Appendix D.

The following is a summary of the opinions of Duane, Morris & Heckscher LLP, counsel to the Partnerships (collectively, the "Partnership"), which represent counsel's opinions on all material federal income tax consequences to the Partnership and to 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 certain tax issues depends upon future facts and circumstances not known to counsel as of the date of this prospectus; thus, no assurance as to the final resolution of such issues should be drawn from the following discussion.

The following statements are based upon the provisions of the Internal Revenue Code of 1986, as amended (the "Code"), existing and proposed regulations thereunder, current administrative rulings, and court decisions. It is possible that legislative or administrative changes or future court decisions may significantly modify the statements and opinions expressed herein. Such changes could be retroactive with respect to the transactions prior to the date of such changes.

Moreover, uncertainty exists concerning some of the federal income tax aspects of the transactions being undertaken by the Partnership. Some of the tax positions being taken by the Partnership may be challenged by the Internal Revenue Service (the "Service") and any such challenge could be successful. Thus, there can be no assurance that all of the anticipated tax benefits of an investment in the Partnership will be realized.

Counsel's opinion is based upon the transactions described in this prospectus (the "Transaction") and upon facts as they have been represented to counsel or determined by it as of the date of the opinion. Any alteration of the facts may adversely affect the opinions rendered.

Because of the factual nature of the inquiry, and in certain cases the lack of clear authority in the law, it is not possible to reach a judgment as to the outcome on the merits (either favorable or unfavorable) of certain material federal income tax issues as described more fully herein.

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 Program, 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 IDC 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 such general partner interest is so held will not be limited by the passive activity provisions. See "Passive Loss and Credit Limitations."

6. Limited Partners' interests (other than those held by Additional General Partners who convert their interests into Limited Partners' interests) will be considered a passive activity within the meaning of Code Section 469 and losses generated therefrom will be limited by the passive activity provisions. See "Passive Loss and Credit Limitations."

7. The Partnership will not be terminated solely as the result of the conversion of Partnership interests. See "Conversion of Interests."

8. To the extent provided 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 Transaction. See "Profit Motive."

3. Whether each Partner will be entitled to percentage depletion since such a determination is dependent upon the status of the Partner as an independent producer and on the Partner's other oil and gas production. Due to the inherently factual nature of such a determination, counsel is unable to render an opinion as to the availability of percentage depletion. See "Depletion Deductions."

4. Whether any interest incurred by a Partner with respect to any borrowings will be deductible or subject to limitations on deductibility, due to the factual nature of the issue. Without any assistance 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 such loans, counsel is unable to express an opinion with respect to the deductibility of any interest paid or incurred on such 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 such treatment. See "Transaction Fees."

General Information: Certain matters contained in this "Tax 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 certain 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:

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 such counsel's best judgment. There can be no assurance that the Service will not successfully assert positions which are inconsistent with the opinions of counsel set forth in this discussion and Appendix D or in the tax reporting positions taken by the Partners or the Partnership. 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.

Each Partnership will be formed as a limited partnership pursuant to 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.

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 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.

Congress granted to the Treasury Secretary the authority to prescribe regulations that would allow taxpayers the option of deducting, rather than capitalizing, intangible drilling and development costs ("IDC"). The Secretary's rules state that, in general, the option to deduct IDC applies only to expenditures for drilling and development items that do not have a salvage value.

The prospectus provides that 87% of the Investor Partners' capital contributions (i.e, subscriptions net of Dealer Manager commissions, discounts, due diligence expenses, and wholesaling costs and the management fee) will be utilized for IDC, which is deductible in the year of investment. As a result, Additional General Partners will realize a deduction of 87% of their investment against any form of income in the year in which the investment is made, provided wells are spudded within the first 90 days of the following year. The deduction by Limited Partners will be restricted to passive income. Based on an 87% deduction, a one Unit ($20,000) investor in a 39.6% marginal Federal tax bracket would reduce taxes payable by $6,890. The investor could also realize additional tax savings on state income taxes in many states, and self-employed investors could realize additional tax savings on self-employment taxes.

A. Classification of Costs

In general, IDC consists of those costs which in and of themselves have no salvage value. In previous partnerships sponsored by 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, such 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 AMT (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. Certain other requirements must also be met. Although PDC will attempt to satisfy each requirement of the Service and judicial authority for deductibility of IDC in 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 such challenge, the Partners' deductions for IDC would be deferred to later years.

C. Recapture of IDC

IDC previously deducted that is allocable to the property (directly or through the ownership of an interest in a partnership) and which would have been included in the adjusted basis of the property is recaptured to the extent of any gain realized upon the disposition of the property. Treasury regulations provide that recapture is determined at the partner level (subject to certain anti-abuse provisions). Where only a portion of recapture property is disposed of, any IDC related to the entire property is recaptured to the extent of the gain realized on the portion of the property sold. In the case of the disposition of an undivided interest in a property (as opposed to the disposition of a portion of the property), a proportionate part of the IDC with respect to the property is treated as allocable to the transferred undivided interest to the extent of any realized gain.

The owner of an economic interest in an oil and gas property is entitled to claim the greater of percentage depletion or cost depletion with respect to oil and gas properties which qualify for such depletion methods. Percentage depletion is generally available only with respect to the domestic oil and gas production of certain "independent producers." In order to qualify as an independent producer, the taxpayer, either directly or through certain related parties, may not be involved in the refining of more than 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 pursuant to which a deduction equal to a percentage of the taxpayer's gross income from each property is allowed in any taxable year, with the aggregate deduction limited to 65% of the taxpayer's taxable income for the year (computed without regard to percentage depletion and net operating loss and capital loss carrybacks). The allowable deduction is limited to 100% of 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 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.

The Partnership will claim depreciation, cost recovery, and amortization deductions with respect to its basis in Partnership property as permitted by the Code. For most tangible personal property placed in service after December 31, 1986, the "modified accelerated cost recovery system" ("MACRS") must be used in calculating the cost recovery deductions. Thus, the cost of lease equipment and well equipment, such as casing, tubing, tanks, and pumping units, and the cost of oil or gas pipelines cannot be deducted currently but must be capitalized and recovered under MACRS. The cost recovery deduction for most equipment used in domestic oil and gas exploration and production and for most of the tangible personal property used in natural gas gathering systems is calculated using the 200% declining balance method switching to the straight-line method, a seven-year recovery period, and a half-year convention. If an accelerated depreciation method is used, a portion of the depreciation will be a preference item for AMT purposes. You will not be able to claim depreciation deductions because all tangible costs have been allocated to us.

In the Transaction, the Investor Partners will acquire their interests by remitting cash in the amount of $20,000 per Unit to the Partnership. In no event will the Partnership accept notes in exchange for a Partnership interest. Nevertheless, without any assistance from 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 any such loans, counsel is unable to express an opinion with respect to the deductibility of any interest paid or incurred on such loans.

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 such expenses and counsel expresses no opinion with respect to the allocation of the fees to deductible and nondeductible items.

Generally, expenditures made in connection with the creation of, and with sales of interests in, a partnership will fit within one of several categories.

A partnership may elect to amortize and deduct its organizational expenses ratably over a period of not less than 60 months commencing with the month the partnership begins business. Examples of organizational expenses are legal fees for services incident to the organization of the partnership, such as negotiation and preparation of a partnership agreement, accounting fees for services incident to the organization of the partnership, and filing fees.

No deduction is allowable for "syndication expenses," examples of which include brokerage fees, registration fees, legal fees of the underwriter or placement agent and the issuer (general partners or the partnership) for securities advice and for advice pertaining to the adequacy of tax disclosures in the prospectus or private placement memorandum for securities law purposes, printing costs, and other selling or promotional material. These costs must be capitalized. Payments for services performed in connection with the acquisition of capital assets must be amortized over the useful life of such assets.

No deduction is allowable with respect to "start-up expenditures," although such expenditures may be capitalized and amortized over a period of not less than 60 months.

The Partnership intends to make payments to 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 thereby 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, thereby resulting in increased taxes and in liability for interest and penalties.

A Partner's share of Partnership losses will be allowed only to the extent of the aggregate amount with respect to which the taxpayer is "at risk" for such activity at the close of the taxable year. In general, a Partner is "at risk" to the extent of the amount of cash and the adjusted basis of other property contributed to the Partnership. Any such loss disallowed by the "at risk" limitation shall be treated as a deduction allocable to the activity in the first succeeding taxable year.

The Code provides that a taxpayer must recognize taxable income to the extent that his "at risk" amount is reduced below zero. This recaptured income is limited to the sum of the loss deductions previously allowed to the taxpayer, less any amounts previously recaptured. A taxpayer may be allowed a deduction for the recaptured amounts included in his taxable income if and when he increases his amount "at risk" in a subsequent taxable year.

The Partners will purchase Units by tendering cash to the Partnership. To the extent the cash contributed constitutes the "personal funds" of the Partners, the Partners should be considered at risk with respect to those amounts. To the extent the cash contributed constitutes "personal funds," in the opinion of counsel, neither the at risk rules nor the adjusted basis rules will limit the deductibility of losses generated from the Partnership. In no event, however, may a partner utilize his distributive share of partnership loss where such share exceeds the partner's basis in the partnership.

A. Introduction

The deductibility of losses generated from passive activities will be limited for certain taxpayers. The passive activity loss limitations apply to individuals, estates, trusts, and personal service corporations as well as, to a lesser extent, closely held C corporations.

The definition of a "passive activity" generally encompasses all rental activities as well as all activities with respect to which the taxpayer does not "materially participate." Notwithstanding this general rule, however, the term "passive activity" does not include "any working interest in any oil or gas property which the taxpayer holds directly or through an entity which does not limit the liability of the taxpayer with respect to such interest." A taxpayer will be considered as materially participating in a venture only if the taxpayer is involved in the operations of the activity on a "regular, continuous, and substantial" basis. In addition, no limited partnership interest will be treated as an interest with respect to which a taxpayer materially participates.

A passive activity loss ("PAL") is the amount by which the aggregate losses from all passive activities for the taxable year exceed the aggregate income from all passive activities for such year.

Individuals and personal service corporations will be entitled to PALs only to the extent of their passive income whereas closely held C corporations (other than personal service corporations) can offset PALs against both passive and net active income, but not against portfolio income. In calculating passive income and loss, however, all activities of the taxpayer are aggregated. PALs disallowed as a result of the above rules will be suspended and can be carried forward indefinitely to offset future passive (or passive and active, in the case of a closely held C corporation) income.

Upon the disposition of an entire interest in a passive activity in a fully taxable transaction not involving a related party, any passive loss that was suspended by the provisions of the passive activity rules is deductible from either passive or non-passive income. The deduction must be reduced, however, by the amount of income or gain realized from the activity in previous years.

B. General Partner Interests

A Limited Partner`s interest in the Partnership will be considered a passive activity and losses generated while such 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 such 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 such 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 pursuant to 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 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 invests in the Partnership as a Limited Partner, his distributive share of the Partnership's losses will be treated as PALs, the availability of which will be limited to the Partner's passive income. If the Partner does not have sufficient passive income to utilize the PAL, the disallowed PAL will be suspended and may be carried forward to be deducted against passive income arising in future years. Further, upon the disposition of the interest to an unrelated party, in a fully taxable transaction such suspended losses will be available, as described above.

Limited Partners should generally be entitled to offset their distributive shares of passive income from the Partnerships with deductions from other passive activities.

The Partnership, in the opinion of counsel, will not be terminated solely as a result of the conversion by Additional General Partners of their Partnership interests into limited partnership interests. In the event a constructive termination does occur, however, there will be a deemed distribution of the Partnership's assets to the Partners and a recontribution by such Partners to the Partnership. This constructive termination could have adverse Federal income tax consequences, described in the opinion in Appendix D. For a discussion of the conversion feature of the Program, see "Terms of the Offering - Conversion of Units by Additional General Partners."

Tax benefits associated with oil and gas exploration activities similar to that of the Program have been subject to the AMT in the past. Specifically, prior to January 1, 1993, intangible drilling cost ("IDC") was an AMT preference item to the extent that "excess IDC" exceeded 65% of a taxpayer's net income from oil and gas properties for the year. Excess IDC was the amount by which the taxpayer's IDC deduction exceeded the deduction that would have been allowed if the IDC had been capitalized and amortized on a straight-line basis over ten years. Percentage depletion, to the extent it exceeded a property's basis, was also an AMT preference item.

For independent producers in taxable years beginning after 1992, the Energy Policy Act repealed the treatment of percentage depletion as a preference item for AMT purposes and provided a limited benefit from the preference on expensing IDC. However, their AMTI may not be reduced by more than 40% of the AMTI determined without this benefit.

For corporations, other than integrated oil companies, the adjusted current earning ("ACE") adjustments were also repealed.

In the event some or all of the property of the Partnership is sold, or upon sale of a Unit (including a sale under the Unit Repurchase Program), an investor will recognize gain to the extent the amount realized exceeds his basis in the investment. In addition, there may be recapture of IDCs and depletion which is treated as additional ordinary income for tax purposes. If the gain exceeds the amount of the recaptured income, the investor will recognize ordinary income to the extent of the recapture and capital gains for the balance.

It is possible that an investor will be required to recognize ordinary income pursuant to the recapture rules in excess of the taxable income of the disposition transaction or in a situation where the disposition transaction resulted in a taxable loss. To balance the excess income, the investor would recognize a capital loss for the difference between the gain and the income. Depending on an investor's particular tax situation, some or all of this loss might be deferred to future years, resulting in a greater tax liability in the year in which the sale was made and a reduced future tax liability.

Any partner who sells or exchanges interests in a partnership must generally notify the partnership in writing within 30 days of such transaction in accordance with Regulations and must attach a statement to his tax return reflecting certain facts regarding the sale or exchange. The notice must include names, addresses, and taxpayer identification numbers (if known) of the transferor and transferee and the date of the exchange. The partnership also is required to provide copies of the information it provides to the Service to the transferor and the transferee.

Any investor who is required to notify the Partnership of a transfer of his Partnership interest, and, who fails to do so, may be fined $50 for each failure, limited to $100,000, provided there is no intentional disregard of the filing requirement. Similarly, the Partnership may be fined for failure to report the transfer. The partnership's penalty is $50 for each failure, limited to $250,000, provided there is no intentional disregard of the filing requirement.

The tax consequences to an assignee purchaser of a Unit from a Partner are not described in this prospectus. Any assignor of a Unit should advise his assignee to consult his own tax advisor regarding the tax consequences of such assignment.

Under the Code, any increase in a partner's share of partnership liabilities, or any increase in such partner's individual liabilities by reason of an assumption by him of partnership liabilities is considered to be a contribution of money by the partner to the partnership. Similarly, any decrease in a partner's share of partnership liabilities or any decrease in such partner's individual liabilities by reason of the partnership's assumption of such individual liabilities will be considered as a distribution of money to the partner by the partnership.

The Partners' adjusted bases in their Units will initially consist of the cash they contribute to the Partnership. Their bases will be increased by their share of Partnership income and additional contributions and decreased by their share of Partnership losses and distributions. To the extent that such actual or constructive distributions are in excess of a Partner's adjusted basis in his Partnership interest (after adjustment for contributions and his share of income and losses of the Partnership), that excess will generally be treated as gain from the sale of a capital asset. In addition, gain could be recognized to a distributee partner upon the disproportionate distribution to a partner of unrealized receivables or substantially appreciated inventory. The limited partnership agreement prohibits distributions to any Investor Partner to the extent such would create or increase a deficit in the Partner's capital account.

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.

The existence of economic, nontax motives for entering into the Transaction is essential if the Partners are to obtain the tax benefits associated with an investment in the Partnership.

Where an activity entered into by an individual is not engaged in for profit, the individual's deductions with respect to that activity are limited to those not dependent upon the nature of the activity (e.g., interest and taxes); any remaining deductions will be limited to gross income from the activity for the year. Should it be determined that a Partner's activities with respect to the Transaction are "not for profit," the Service could disallow all or a portion of the deductions generated by the Partnership's activities.

The Code generally provides for a presumption that an activity is entered into for profit where gross income from the activity exceeds the deductions attributable to such activity for three or more of the five consecutive taxable years ending with the taxable year in question. At the taxpayer's election, such presumption can relate to three or more of the taxable years in the 5-year period beginning with the taxable year in which the taxpayer first engages in the activity.

Due to the inherently factual nature of a Partner's intent and motive in engaging in the Transaction, counsel does not express an opinion as to the ultimate resolution of this issue in the event of a challenge by the Service. Partners must, however, seek to make a profit from their activities with respect to the Transaction beyond any tax benefits derived from those activities or risk losing those tax benefits.

Returns and Audits. While no federal income tax is required to be paid by an organization classified as a partnership for federal income tax purposes, a partnership must file federal income tax information returns, which are subject to audit by the Service. Any such audit may lead to adjustments, in which event you may be required to file amended personal federal income tax returns. Any such 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 such administrative proceedings and decisions therein, except in the case of partners with less than 1% profits interest in a partnership having more than 100 partners. If a group of partners having an aggregate profits interest of 5% or more in such a partnership so requests, however, the Service also must mail notice to a partner appointed by that group to receive notice. All partners, whether or not entitled to notice, are entitled to participate in the administrative proceedings at the partnership level, although the limited partnership agreement provides for waiver of certain of these rights by the Investor Partners. All Investor Partners, including those not entitled to notice, may be bound by a settlement reached by the Partnership's representative "tax matters partner," which will be Petroleum Development Corporation. If a proposed tax deficiency is contested in any court by any Partner of a Partnership or by us, all Partners of that Partnership may be deemed parties to such litigation and bound by the result reached therein.

Consistency Requirements. You must generally treat Partnership items on your federal income tax returns consistently with the treatment of such 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 such item by the taxpayer. In the case of partnerships, the disclosure is to be made on the return of the partnership. Under the applicable Regulations, however, an individual partner may make adequate disclosure with respect to partnership items if certain conditions are met.

In the case of understatements attributable to "tax shelter" items, the substantial understatement penalty may be avoided only if the taxpayer establishes that, in addition to having substantial authority for his position, he reasonably believed the treatment claimed was more likely than not the proper treatment of the item. A "tax shelter" item is one that arises from a partnership (or other form of investment) the principal purpose of which is the avoidance or evasion of federal income tax. Under the GATT legislation, a corporation is generally held to a higher standard to avoid the substantial understatement penalty.

Based on the definition of a "tax shelter" in the Regulations, performance of previous partnerships sponsored by 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 such. See "Prior Activities - Tax Deductions and Tax Credits of Participants in Previous Partnerships," above.

The Partnership will use the accrual method of accounting and will select the calendar year as its taxable year.

A General Partner's share of any income or loss attributable to Units will constitute "net earnings from self-employment" for both social security and self-employment tax purposes, while a Limited Partner's share of such items will not constitute "net earnings from self-employment." Thus, no quarters of coverage or increased benefits under the Social Security Act will be earned by Limited Partners.

The opinions expressed herein 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.

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 General Partner Interests or Limited Partner Interests. You should review such 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.

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.

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 Partners, by execution of the Partnership Agreement, grant to the Managing General Partner the exclusive authority to manage the Partnership business in its sole discretion and to thereby bind the Partnership and all Partners in its conduct of the Partnership business. The Additional General Partners may not participate in the management of the Partnership business; and the limited partnership agreement prohibits the Additional General Partners from acting in a manner harmful to the assets or the business of the Partnership or to do any other act which would make it impossible to carry on the ordinary business of the Partnership. If an Additional General Partner acts in contravention of the terms of the limited partnership agreement, losses caused by his or her actions will be borne by such Additional General Partner alone and such Additional General Partner may be liable to other Partners for all damages resulting from his or her breach of the limited partnership agreement. Section 7.01. Additional General Partners who choose to assign their Units in the future may do so only as provided in the limited partnership agreement and liability of Partners who have assigned their Units may continue after such assignment unless a formal assumption and release of liability is effected. Section 7.03.

The West Virginia Uniform Limited Partnership Act will govern the Partnerships, under which law a Limited Partner's liability for the obligations of the Partnership is limited to his or her capital contribution, his or her share of Partnership assets and the return of any part of his or her capital contribution for a period of one year after such return (or six years in the event such return is in violation of the 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, such person takes part in the control of the business of the Partnership. Section 7.01.

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 such distribution will create or increase a deficit in that Partner's capital account (as increased by his or her share of Partnership minimum gain). Section 4.03.

Liquidating Distributions: Liquidating distributions will be made in the same manner as regular distributions; however, in the event of dissolution of the Partnership, distributions will be made only after due provision has been made for, among other things, payment of all Partnership debts and liabilities. Section 9.03.

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 such meeting, in person or by proxy, at the meeting at which a quorum is present. Approval of any of the following matters requires a vote of a majority of the then outstanding Units entitled to vote:

(a) The sale of all or substantially all of the assets of the Partnership;

(b) Removal of the Managing General Partner and election of a new managing general partner;

(c) Dissolution of the Partnership;

(d) Any non-ministerial amendment to the limited partnership agreement;

(e) Cancellation of contracts for services with the Managing General Partner or affiliates; and

(f) The appointment of a liquidating trustee in the event the Partnership is to be dissolved by reason of the retirement, dissolution, liquidation, bankruptcy, death, or adjudication of insanity or incapacity of the last remaining General Partner .

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.

In the event that the Managing General Partner desires to withdraw from the Partnership for whatever reason, it may do so only upon one hundred twenty (120) days prior written notice and with the written consent of the Investor Partners owning a majority of the then outstanding Units. Section 6.03.

In the event that the Investor Partners desire to remove the Managing General Partner, they may do so at any time upon ninety (90) days written notice, with the consent of the Investor Partners owning a majority of the then outstanding Units, and upon the selection of a successor managing general partner, within such ninety-day period, by the Investor Partners owning a majority of the then outstanding Units. Section 7.06.

The Partnership will continue for a maximum period ending December 31, 2051 unless earlier dissolved upon the occurrence of any of the following:

(a) the written consent of the Investor Partners owning a majority of the then outstanding Units;

(b) the retirement, bankruptcy, adjudication of insanity or incapacity, withdrawal, removal, or death (or, in the case of a corporate managing general partner, the retirement, withdrawal, removal, dissolution, liquidation, or bankruptcy) of a managing general partner, unless a successor managing general partner is selected by the Partners pursuant to the limited partnership agreement or the remaining managing general partner, if any, continues the Partnership's business;

(c) the sale, forfeiture, or abandonment of all or substantially all of the Partnership's property; or

(d) the occurrence of any event causing dissolution of the Partnership under the laws of the State of West Virginia.

Section 9.01.

The Managing General Partner has agreed to indemnify each of the Additional General Partners for obligations related to casualty losses which exceed available insurance coverage and Partnership assets. Section 7.02.

If obligations incurred by the Partnership are the result of the negligence or misconduct of an Additional General Partner, or the contravention of the terms of the Partnership Agreement by the Additional General Partner, then the foregoing indemnification by the Managing General Partner will be unenforceable as to such Additional General Partner and such Additional General Partner will be liable to all other Partners for damages and obligations resulting therefrom. Section 7.02.

The Managing General Partner will be entitled to reimbursement and indemnification for all expenditures made (including amounts paid in settlement of claims) or losses or judgments suffered by it in the ordinary and proper course of the Partnership's business, provided that the Managing General Partner has determined in good faith that the course of conduct which caused the loss or liability was in the best interests of the Partnership, that the Managing General Partner was acting on behalf of or performing services for the Partnership, and that such expenditures, losses or judgments were not the result of the negligence or misconduct on the part of the Managing General Partner. Section 6.04. The Managing General Partner will have no liability to the Partnership or to any Partner for any loss suffered by the Partnership which arises out of any action or inaction of the Managing General Partner if the Managing General Partner, in good faith, determined that such course of conduct was in the best interest of the Partnership and such course of conduct did not constitute negligence or misconduct of the Managing General Partner. The Managing General Partner will be indemnified by the Partnership to the limit of the insurance proceeds and tangible net assets of the Partnership against any losses, judgments, liabilities, expenses and amounts paid in settlement of any claims sustained by it in connection with the Partnership, provided that the same were not the result of negligence or misconduct on the part of the Managing General Partner.

Notwithstanding the above, the Managing General Partner will not be indemnified for liabilities arising under Federal and state securities laws unless (1) there has been a successful adjudication on the merits of each count involving securities law violations; or (2) such claims have been dismissed with prejudice on their merits by a court of competent jurisdiction; or (3) a court of competent jurisdiction approves a settlement of such claims against a particular indemnitee and finds that indemnification of the settlement and the related costs should be made, and the court considering the request for indemnification has been advised of the position of the Securities and Exchange Commission and of the position of any state securities regulatory authority in which securities of the Partnership were offered or sold as to indemnification for violations of securities laws; provided, however, the court need only be advised of the positions of the securities regulatory authorities of those states (i) which are specifically set forth in the prospectus and (ii) in which plaintiffs claim they were offered or sold Partnership Units.

In any claim for indemnification for Federal or state securities laws violations, the party seeking indemnification must place before the court the position of the Securities and Exchange Commission and the Massachusetts Securities Division or other respective state securities division with respect to the issue of indemnification for securities laws violations.

The Partnership will not incur the cost of the portion of any insurance which insures any party against any liability as to which such party is herein prohibited from being indemnified. Section 6.04.

The Managing General Partner will furnish to the Investor Partners of each Partnership certain semi-annual and annual reports which will contain financial statements (including a balance sheet and statements of income, Partners' equity and cash flows), which statements at fiscal year end will be audited by an independent accounting firm and will include a reconciliation of such statements with information provided to the Investor Partners for Federal income tax purposes. Financial statements furnished in a Partnership's semi-annual reports will not be audited. Semi-annually, all Investor Partners will also receive a summary itemization of the transactions between the Managing General Partner or any affiliate thereof and the Partnership showing all items of compensation received by the Managing General Partner and its affiliates. Annually beginning with the fiscal year ended December 31, 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 Program, reports containing a description of the Partnership's acquisition of interests in prospects, including farmins and farmouts, and the drilling, completion and abandonment of wells thereon. All Investor Partners will receive a report containing information necessary for the preparation of their Federal income tax returns and any required state income tax returns by March 15 of each calendar year. Investor Partners will also receive in such monthly reports a summary of the status of wells drilled by the Partnership, the amount of oil or gas from each well and the drilling schedule for proposed wells, if known. The Managing General Partner may provide such other reports and financial statements as it deems necessary or desirable. Section 8.02.

Each Partner will grant to the Managing General Partner a power of attorney to execute certain documents deemed by the Managing General Partner to be necessary or convenient to the Partnership's business or required in connection with the qualification and continuance of the Partnership. Section 10.01.

Other provisions of the limited partnership agreement are summarized in this Prospectus under the headings "Terms of the Offering," "Source of Funds and Use of Proceeds," "Participation in Costs and Revenues," "Management," "Fiduciary Responsibility of the Managing General Partner," and "Transferability of Units." We direct the attention of prospective investors to these sections.

TRANSFERABILITY OF UNITS

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 such an assignment, or which, in the opinion of counsel to the Partnership, would result in the Partnership being treated as a publicly traded partnership, or which, in the opinion of counsel to the Partnership, may not be effected without registration under the Securities Act of 1933, as amended, or would result in the violation of any applicable state securities laws.

A substituted Additional General Partner will have the same rights and responsibilities, including unlimited liability, in the Partnership as every other Additional General Partner. Upon receipt of notice of a purported transfer or assignment of a Unit of general partnership interest, we, after having determined that the purported transferee satisfies the suitability standards of an Additional General Partner and other conditions established by the Program, will promptly notify the purported transferee of the Partnership's consent to the transfer and will include with the notice a copy of the limited partnership agreement, together with a signature page. In such 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. A Partnership need not recognize any assignment until the instrument of assignment has been delivered to us. The assignee of such interests has certain rights of ownership but may become a substituted Investor Partner and thus be entitled to all of the rights of an Additional General Partner or Limited Partner only upon meeting certain conditions, including (i) obtaining our consent to such substitution, (ii) paying all costs and expenses incurred in connection with such substitution, (iii) making certain representations to us and (iv) 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. Moreover, upon written notice to us, Additional General Partners will have the right to convert their interests into limited partnership interests and thereafter become Limited Partners of the Partnership. See "Terms of the Offering - Conversion of Units by the Managing General 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 certain conditions. See "Terms of the Offering - Unit Repurchase Program."

PLAN OF DISTRIBUTION

We are offering for sale units of preformation limited and general partnership interest through PDC Securities Incorporated, the Dealer Manager, 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.

No sales commissions will be paid on sales of Units to officers, directors, employees, or registered representatives of a Soliciting Dealer if such Soliciting Dealer, in its discretion, has elected to waive such sales commissions. Any Units so purchased will be held for investment and not for resale.

We, the Dealer Manager, and soliciting dealers have agreed to indemnify one another against certain civil liabilities, including liability under the Securities Act of 1933, as amended. Members of the selling group may be deemed to be "underwriters" as defined under the Securities Act of 1933, as amended, and their commissions and other payments may be deemed to be underwriting compensation.

The Dealer Manager may offer the Units and receive commissions in connection with the sale of Units only in those states in which it is lawfully qualified to do so.

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, thereby satisfying 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 certain aspects of the Program, namely, a Program highlight information piece which will constitute the prospectus summary ("Program Summary" in bullet format), an introduction to the Program ("Flip Chart/Slide Presentation"), and prospect letters ("Broker-Dealer Guide"). The Program may also utilize a Program general summary piece ("Program Summary" in text format), a sheet presenting information regarding comparative investment deductions ("Investment Deductions"), and a Web site at www.pdcgas.com. Such sales material will not contain any material information which is not also set forth in the prospectus. The offering of Units will be made only by means of this prospectus.

LEGAL OPINIONS

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 herein and in the Registration Statement have been included herein and in the Registration Statement in reliance upon the reports of KPMG LLP, independent auditors, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

ADDITIONAL INFORMATION

A Registration Statement on Form S-1 (Reg. No. 333- ) with respect to the Units offered hereby has been filed on behalf of the Partnerships with the Securities and Exchange Commission, Washington, D.C. 20549, under the Securities Act of 1933, as amended. This prospectus does not contain all of the information set forth in the Registration Statement, certain portions of which have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. Reference is made to such Registration Statement, including exhibits, for further information. 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 Registration Statement, as well as all exhibits and amendments thereto, have been filed and will be filed electronically with the Commission through the Electronic Data Gathering, Analysis, and Retrieval ("EDGAR") system. Such Registration Statement and all exhibits and amendments thereto are publicly available through the Commission's 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 thereof, and we qualify each such statement in this prospectus in all respects by this reference. You may obtain copies of any materials filed as a part of the Registration Statement from the Securities and Exchange Commission by payment of the requisite fees therefor or you may 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 herein is correct as of any time subsequent to the date hereof.

GLOSSARY OF TERMS

Act: The West Virginia Uniform Limited Partnership Act.

Additional General Partners: Those Investor Partners who purchase Units as additional general partners, and their transferees and assigns.

Administrative Costs: All customary and routine expenses incurred by the Managing General Partner for the conduct of program administration, including legal, finance, accounting, secretarial, travel, office rent, telephone, data processing and other items of a similar nature.

Affiliate: An affiliate of a specified person means (a) any person directly or indirectly owning, controlling, or holding with power to vote 10 percent or more of the outstanding voting securities of such specified person; (b) any person 10 percent or more of whose outstanding voting securities are directly or indirectly owned, controlled, or held with power to vote, by such specified person; (c) any person directly or indirectly controlling, controlled by, or under common control with such specified person; (d) any officer, director, trustee or partner of such specified person; and (e) if such specified person is an officer, director, trustee or partner, any person for which such person acts in any such capacity.

Assessment: Additional amounts of capital which may be mandatorily required of or paid voluntarily by an Investor Partner beyond his subscription commitment.

Capital Accounts: The accounts to be maintained for each Partner on the books and records of the Partnership pursuant to Section 3.01 of the 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 such Investor Partner to the capital of the Partnership pursuant to Section 2.02 of the limited partnership agreement and, with respect to the Managing General Partner and Initial Limited Partner, the total investment, including the original investment, assessments and amounts reinvested, to the capital of the Partnership pursuant to Section 2.01 of the 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 pursuant to the provisions of the Internal Revenue Code.

Carried Interest: An equity interest in a program issued to a person without consideration, in the form of cash or tangible property, in an amount proportionately equivalent to that received from the participants.

Code: The Internal Revenue Code of 1986, as amended.

Cost: When used with respect to the sale of property to the Partnership, means (a) the sum of the prices paid by the seller to an unaffiliated person for such property, including bonuses; (b) title insurance or examination costs, brokers' commissions, filing fees, recording costs, transfer taxes, if any, and like charges in connection with the acquisition of such property; (c) a pro rata portion of the seller's actual necessary and reasonable expenses for seismic and geophysical services; and (d) rentals and ad valorem taxes paid by the seller with respect to such property to the date of its transfer to the buyer, interest and points actually incurred on funds used to acquire or maintain such property, and such portion of the seller's reasonable, necessary and actual expenses for geological, engineering, drafting, accounting, legal and other like services allocated to the property cost in conformity with generally accepted accounting principles and industry standards, except for expenses in connection with the past drilling of wells which are not producers of sufficient quantities of oil or gas to make commercially reasonable their continued operations, and provided that the expenses enumerated in this subsection (d) hereof shall have been incurred not more than 36 months prior to the purchase by the Partnership; provided that such period may be extended, at the discretion of the state securities administrator, upon proper justification. When used with respect to services, "cost" means the reasonable, necessary and actual expense incurred by the seller on behalf of the Partnership in providing such services, determined in accordance with generally accepted accounting principles. As used elsewhere, "cost" means the price paid by the seller in an arm's-length transaction.

Dealer Manager: PDC Securities Incorporated, 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 such services are provided pursuant to 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 whereby the owner of a leasehold or working interest agrees to assign an interest in certain specific acreage to the assignees, retaining an interest such as an overriding royalty interest, an oil and gas payment, offset acreage or other type of interest, subject to the drilling of one or more specific wells or other performance as a condition of the assignment.

Horizon: A zone of a particular formation; that part of a formation of sufficient porosity and permeability to form a petroleum reservoir.

IDC: Intangible drilling and development costs.

Independent Expert: A person with no material relationship to the Managing General Partner who is qualified and who is in the business of rendering opinions regarding the value of oil and gas properties based upon the evaluation of all pertinent economic, financial, geologic and engineering information available to the Managing General Partner.

Initial Limited Partner: Steven R. Williams or any successor to his interest.

Investor Partner: Any investor participating in the Partnership as an Additional General Partner or a Limited Partner, but excluding the Managing General Partner and Initial Limited Partner.

Landowners' Royalty Interest: An interest in production, or the proceeds therefrom, to be received free and clear of all costs of development, operation, or maintenance, reserved by a landowner upon the creation of an oil and gas lease.

Lease: Full or partial interests in: (i) undeveloped oil and gas leases; (ii) oil and gas mineral rights; (iii) licenses; (iv) concessions; (v) contracts; (vi) fee rights; or (vii) other rights authorizing the owner thereof to drill for, reduce to possession and produce oil and gas.

Limited Partners: Those Investor Partners who purchase Units as Limited Partners, transferees or assignees who become Limited Partners, or Additional General Partners whose interests are converted to limited partnership interests pursuant to 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 Federal income tax laws.

Management Fee: The fee to which the Managing General Partner is entitled pursuant to Section 6.06 of the limited partnership agreement.

Managing General Partner: Petroleum Development Corporation or its successors.

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 such earlier date as the Managing General Partner, in its sole and absolute discretion, shall select.

Oil and Gas Interest: Any oil or gas royalty or lease, or fractional interest therein, or certificate of interest or participation or investment contract relative to such royalties, leases or fractional interests, or any other interest or right which permits the exploration of, drilling for, or production of oil and gas or other related hydrocarbons or the receipt of such production or the proceeds thereof.

Operating Costs: Expenditures made and costs incurred in producing and marketing oil or gas from completed wells, including, in addition to labor, fuel, repairs, hauling, materials, supplies, utility charges and other costs incident to or therefrom, ad valorem and severance taxes, insurance and casualty loss expense, and compensation to well operators or others for services rendered in conducting such operations.

Organization and Offering Costs: All costs of organizing and selling the offering including, but not limited to, total underwriting and brokerage discounts and commissions (including fees of the underwriters' attorneys), expenses for printing, engraving, mailing, salaries of employees while engaged in sales activity, charges of transfer agents, registrars, trustees, escrow holders, depositaries, engineers and other experts, expenses of qualification of the sale of the securities under federal and state law, including taxes and fees, accountants' and attorneys' fees and other frontend fees.

Overriding Royalty Interest: An interest in the oil and gas produced pursuant to a specified oil and gas lease or leases, or the proceeds from the sale thereof, carved out of the working interest, to be received free and clear of all costs of development, operation, or maintenance.

Participant: The purchaser of a Unit in the Program.

Partners: The Managing General Partner, the Additional General Partners other than the Managing General Partner, and the Limited Partners. Reference to a "Partner" shall mean any one of the Partners.

Partnership or Partnerships: One or all of the limited partnerships to be formed in the PDC 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 Program.

Partnership Minimum Gain: Partnership minimum gain as defined in Treas. Reg. Section 1.704-2(d)(1).

PDC: Petroleum Development Corporation.

Profit: The excess of the Partnership's income and gains over the Partnership's losses and deductions, computed in accordance with the provisions of the Federal income tax laws.

Program: One or more limited partnerships formed, or to be formed, for the primary purpose of exploring for oil or gas. Herein, PDC 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, pursuant to which the Units are being offered and sold.

Proved Developed Oil and Gas Reserves. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved Oil and Gas Reserves: Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

Proved Undeveloped Reserves. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Reservoir: A separate structural or stratigraphic trap containing an accumulation of oil or gas.

Roll-Up: A transaction involving the acquisition, merger, conversion, or consolidation, either directly or indirectly, of the Partnership and the issuance of securities of a roll-up entity. Such term does not include:

(1) voting rights;

(2) the term of existence of the Partnership;

(3) sponsor compensation; or

(4) the Partnership's investment objectives.

Roll-Up Entity: A partnership, trust, corporation or other entity that would be created or survive after the successful completion of a proposed roll-up transaction.

Royalty: A fractional undivided interest in the production of oil and gas wells, or the proceeds therefrom to be received free and clear of all costs of development, operations or maintenance. Royalties may be reserved by landowners upon the creation of an oil and gas lease ("landowner's royalty") or subsequently carved out of a working interest ("overriding royalty").

Securities Act: Securities Act of 1933, as amended.

Sponsor: Any person directly or indirectly instrumental in organizing, wholly or in part, a program or any person who will manage or is entitled to manage or participate in the management or control of a program. "Sponsor" includes the managing and controlling general partner(s) and any other person who actually controls or selects the person who controls 25% or more of the exploratory, developmental or producing activities of the Partnership, or any segment thereof, even if that person has not entered into a contract at the time of formation of the Partnership. "Sponsor" does not include wholly independent third parties such as attorneys, accountants, and underwriters whose only compensation is for professional services rendered in connection with the offering of units. Whenever the context of these guidelines so requires, the term "sponsor" shall be deemed to include its affiliates.

Spudding Date: The date that drilling commences.

Subscriptions: The subscription agreement(s) or the amount indicated on the subscriptions agreements that the Additional General Partners and the Limited Partners have agreed to pay to a Partnership.

Tangible Costs: Those costs which are generally accepted as capital expenditures pursuant to the provisions of the Code.

Treas. Reg.: A regulation promulgated by the Treasury Department under Title 26 of the United States Code.

Unit: An undivided interest of an Investor Partner in the aggregate interest in the capital and profits of the Partnership.

Well Head Gas Price: The price paid by a gas purchaser for gas produced from Partnership wells excluding any tax reimbursements or transportation allowances.

Wholesaling Fee: A fee paid to a representative of the Dealer Manager who helps introduce and explain the Program to registered representatives with firms executing a selling agreement with the Dealer Manager for the Program.

Working Interest: An interest in an oil and gas leasehold which is subject to some portion of the costs of development, operation, or maintenance.

7,500 Preformation Units of

General and Limited

Partnership Interest

[PDC logo]

DRILLING PROGRAM

$150,000,000

Aggregate Subscriptions

PROSPECTUS

Dated , 2001

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

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

(Continued)

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

December 31, 1999 and 1998

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.

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Balance Sheets

December 31, 1999 and 1998

(1) Summary of Significant Accounting Policies

Principles of Consolidation

Cash Equivalents

Inventories

Oil and Gas Properties

(Continued)

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Balance Sheets (Continued)

December 31, 1999 and 1998

Transportation Equipment, Pipelines and Other Equipment

Buildings

(Continued)

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Balance Sheets (Continued)

December 31, 1999 and 1998

Advances for Future Drilling Contracts

Retirement Plans

Revenue Recognition

Income Taxes

Derivatives

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Balance Sheets (Continued)

December 31, 1999 and 1998

Stock Compensation

Fair Value of Financial Instruments

New Accounting Standards

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Balance Sheets

December 31, 1999 and 1998

(3) Long-Term Debt

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)

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:

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

Notes to Consolidated Balance Sheets (Continued)

December 31, 1999 and 1998

(7) Transactions with Affiliates

(Continued)

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Balance Sheets

December 31, 1999 and 1998

(8) Commitments and Contingencies

(9) Acquisitions

(Continued)

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Balance Sheets

December 31, 1999 and 1998

(10) Derivatives and Hedging Activities

(11) Costs Incurred in Oil and Gas Property Acquisition, Exploration and

Development Activities

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

(Continued)

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Balance Sheets

December 31, 1999 and 1998

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

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

(Continued)

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Balance Sheets

December 31, 1999 and 1998

Gas (MCF)

1999 1998

Proved developed and

Beginning of year 29,000 45,000

End of year 798,000 29,000

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

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

(Continued)

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Balance Sheets

December 31, 1999 and 1998

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

(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:

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Balance Sheets

December 31, 1999 and 1998

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

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

June 30, 2000 and December 31, 1999

ASSETS

2000 1999

(Unaudited)

Current assets:

Cash and cash equivalents $ 5,456,900 $ 29,059,200

Accounts and notes receivable 16,430,300 10,263,200

Inventories 525,200 577,600

Prepaid expenses 6,280,000 2,360,100

Total current assets 28,692,400 42,260,100

Properties and equipment 129,987,300 118,349,100

Less accumulated depreciation,

depletion and amortization 34,345,400 31,207,300

95,641,900 87,141,800

Other assets 2,808,300 2,681,700

$127,142,600 $132,083,600

LIABILITIES AND STOCKHOLDERS' EQUITY

Current liabilities:

Accounts payable and accrued expenses $ 20,646,800 $ 17,599,000

Advances for future drilling contracts 4,897,500 25,137,400

Funds held for future distribution 2,594,100 2,027,600

Total current liabilities 28,138,400 44,764,000

Long-term debt, excluding current maturities 14,000,000 9,300,000

Other liabilities 3,695,100 3,160,600

Deferred income taxes 4,530,900 4,134,100

Commitments and contingencies

Stockholders' equity:

Common stock 162,400 157,400

Additional paid-in capital 32,930,100 32,071,000

Retained earnings 43,685,700 38,496,500

Total stockholders' equity 76,778,200 70,724,900

$127,142,600 $132,083,600

PETROLEUM DEVELOPMENT CORPORATION AND SUBSIDIARIES

Notes to Consolidated Balance Sheets

Oil and Gas Properties are reported on the successful efforts method.

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

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 Section Section 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:

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. Section 1.704-2(b)(1). The amount of Nonrecourse Deductions for a Partnership fiscal year shall equal the net increase in the amount of Partnership Minimum Gain during that fiscal year reduced (but not below zero) by the aggregate distributions during that fiscal year of proceeds of a Nonrecourse Liability that are allocable to an increase in Partnership Minimum Gain, determined according to the provisions of Treas. Reg. Section 1.704-2(c).

(ee) "Nonrecourse Liability" shall have the meaning set forth in Treas. Reg. Section Section 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. Section 1.704-2(i).

(ll) "Partner Nonrecourse Debt" shall have the meaning set forth in Treas. Reg. Section 1.704-2(b)(4).

(mm) "Partner Nonrecourse Deductions" shall have the meaning set forth in Treas. Reg. Section 1.704-2(i)(2). The amount of Partner Nonrecourse Deductions with respect to a Partner Nonrecourse Debt for a Partnership fiscal year shall equal the net increase in the amount of Partner Minimum Gain attributable to such Partner Nonrecourse Debt during that fiscal year reduced (but not below zero) by proceeds of the liability distributed during that fiscal year to the Partner bearing the economic risk of loss for such liability that are both attributable to the liability and allocable to an increase in Partner Minimum Gain attributable to such Partner Nonrecourse Debt, determined in accordance with Treas. Reg. Section 1.704-2(i)(3).

(nn) "Partners" shall mean the Managing General Partner, the Initial Limited Partner, and the Investor Partners. "Partner" shall mean any one of the Partners. All references in this Agreement to a majority in interest or a specified percentage of the Partners shall mean Partners holding more than 50% or such specified percentage, respectively, of the outstanding Units then held.

(oo) "Partnership" shall mean the partnership pursuant to this Agreement and the partnership continuing the business of this Partnership in the event of dissolution as herein provided.

(pp) "Partnership Minimum Gain" shall have the meaning set forth in Treas. Reg. Section Section 1.704-2(b)(2) and 1.704-2(d)(1).

(qq) "Permitted Transfer" shall mean any transfer of Units satisfying the provisions of Section 7.03 herein.

(rr) "Person" shall mean any individual, partnership, corporation, trust, or other entity.

(ss) "Profits" and "Losses" shall mean, for each fiscal year or other period, an amount equal to the Partnership's taxable income or loss for such year or period, determined in accordance with Code Section 703(a) (for this purpose, all items of income, gain, loss, or deduction required to be stated separately pursuant to Code Section 703(a)(1) shall be included in taxable income or loss), with the following adjustments:

(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.

(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:

(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.

2.02 Capital Contributions of the Investor Partners.

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.

3.02 Allocation of Profits and Losses.

(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.

3.04 Apportionment Among Partners:

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.

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.

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.

5.03 Acquisition and Sale of Leases.

5.04 Title to Leases.

5.05 Farmouts.

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.

(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:

(m) In connection with a proposed Roll-Up, the following shall apply:

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:

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:

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:

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.

6.06 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 Section Section 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:

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.

7.04 Prohibited Transfers.

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.

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.

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 Section Section 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:

(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.

8.02 Reports. The Managing General Partner shall deliver to each Investor Partner the following financial statements and reports at the times indicated below:

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.

ARTICLE IX

Dissolution; Winding-up

9.01 Dissolution.

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.

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:

10.02 Nature of Special Power. The foregoing grant of authority:

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.

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

APPENDIX B TO PROSPECTUS

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. ( )

IF NO SELECTION IS MADE, WE

CANNOT ACCEPT YOUR

RETURN THIS SUBSCRIPTION AGREE-

Survivorship (both persons must sign)

TO BE COMPLETED BY PETROLEUM DEVELOPMENT CORPORATION

Petroleum Development Corporation, as the Managing General Partner of the Partnership, hereby accepts this Subscription and agrees to hold and invest the same pursuant to the terms and conditions of the Limited Partnership Agreement of the Partnership.

ATTEST: PETROLEUM DEVELOPMENT CORPORATION

Secretary

Title:

Date:

TO BE COMPLETED BY REGISTERED REPRESENTATIVE

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

APPENDIX C TO PROSPECTUS

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).

ATTENTION CALIFORNIA INVESTORS

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;

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:

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.

APPENDIX D TO THE PROSPECTUS