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Position(s)

Barton R. Brookman, Jr.

Gysle R. Shellum

Vice President and Treasurer

Daniel W. Amidon

Vice President and Secretary

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

SCHEDULE 14A

PROXY STATEMENT PURSUANT TO SECTION 14(a) OF THE
SECURITIES EXCHANGE ACT OF 1934

Filed by the Registrant þ
Filed by a Party other than the Registrant o
Check the appropriate box:


o		Preliminary Proxy Statement


o		Confidential, for use of the Commission only (as permitted by Rule 14a-6(e)(2))


þ		Definitive Proxy Statement


o		Definitive Additional Materials

o		Soliciting Material Pursuant to Section 240.14a-12

PDC 2002-D Limited Partnership

(Name of Registrant as Specified In Its Charter)

(Name of Person(s) Filing Proxy Statement if other than the Registrant)

Payment of Filing Fee (Check the appropriate box):

o		No fee required.


o		Fee computed on table below per Exchange Act Rules 14a-6(i)(1) and 0-11.

	(1)		Title of each class of securities to which transaction applies:

			Limited partnership units of PDC 2002-D Limited Partnership



	(2)		Aggregate number of securities to which transaction applies:

			1,312.16 limited partnership units



	(3)		Per unit price or other underlying value of transaction computed pursuant to Exchange Act Rule 0-11 (set forth the amount on which the filing fee is calculated and state how it was determined): The maximum aggregate value of the transaction was calculated by multiplying the 1,312.16 limited partnership units held by limited partners unaffiliated with Petroleum Development Corporation by $4,024 per limited partnership unit. The filing fee was determined by multiplying 0.0001161 by the maximum aggregate value of the transaction as determined in accordance with the preceding sentence.



	(4)		Proposed maximum aggregate value of transaction:

			$5,280,131.84



	(5)		Total fee paid:

			$613


þ		Fee paid previously with preliminary materials.


o		Check box if any part of the fee is offset as provided by Exchange Act Rule 0-11(a)(2) and identify the filing for which the offsetting fee was paid previously. Identify the previous filing by registration statement number, or the Form or Schedule and the date of its filing.

	(1)		Amount Previously Paid:



	(2)		Form, Schedule or Registration Statement No.:



	(3)		Filing Party:



	(4)		Date Filed:

PDC 2002-D LIMITED PARTNERSHIP

1775 Sherman Street, Suite 3000

Denver, Colorado 80203

NOTICE OF SPECIAL MEETING OF INVESTORS
TO BE HELD ON OCTOBER 28, 2011

To the investors in PDC 2002-D Limited Partnership:

NOTICE IS HEREBY GIVEN that PDC 2002-D Limited Partnership, which we refer to as the partnership, will hold a special meeting of its limited partners other than PDC and its affiliates, which we refer to as the investors, at 1775 Sherman Street, Suite 3000, Denver, Colorado 80203 on October 28, 2011 at 10:00 a.m., local time, for the following purposes:


	•	To consider and vote upon a proposal by Petroleum Development Corporation (dba PDC Energy), a Nevada corporation and the managing general partner of the partnership, which we refer to as PDC, to amend the partnership’s limited partnership agreement, which we refer to as the partnership agreement, in order to grant the investors an express right to vote to approve merger transactions such as the one described below.

	•	To consider and vote upon a proposal by PDC to approve the Agreement and Plan of Merger, dated as of June 20, 2011, which we refer to as the merger agreement, by and among the partnership, PDC and DP 2004 Merger Sub, LLC, a Delaware limited liability company and a wholly-owned subsidiary of PDC, which we refer to as the merger sub, pursuant to which the partnership will merge with and into the merger sub, with the merger sub being the surviving entity. Upon consummation of the merger, all of the partnership’s outstanding limited partnership units (other than the limited partnership units owned by PDC or any subsidiary thereof and other than limited partnership units owned by investors who properly exercise appraisal rights) will be converted into the right to receive cash in an amount equal to $4,024 per limited partnership unit, plus the sum of the amounts withheld from per unit cash distributions by the partnership from October 1, 2010 through August 31, 2011 for the partnership’s additional Codell formation development plan, less the sum of the per unit cash distributions made after August 31, 2011 as more fully described in the enclosed proxy statement. The per unit merger amount offered to investors under the merger agreement was determined using an effective transaction date of July 1, 2011. In the event holders of less than a majority of the outstanding limited partnership units held by the investors vote to approve the amendment to the partnership agreement or the merger agreement, PDC will withdraw the offer and the merger will not proceed.

	•	To consider and vote upon any proposal to adjourn or postpone the special meeting to a later date if necessary or appropriate, including an adjournment or postponement to solicit additional proxies if, at the special meeting, the number of limited partnership units present or represented by proxy and voting in favor of the approval of the merger agreement or the amendment to the partnership agreement is insufficient to approve the merger agreement or the amendment to the partnership agreement, respectively.

	•	To transact other business as may properly come before the special meeting.

We describe the amendment to the partnership agreement and the merger agreement more fully in the accompanying proxy statement, which includes a copy of the merger agreement as Appendix A, a copy of the partnership agreement as Appendix F, and a copy of form of the amendment to the partnership agreement as

Appendix G. PDC has fixed the close of business on September 1, 2011 as the record date for determining the investors entitled to notice of the special meeting and to vote at the special meeting and any adjournments or postponements of the meeting. Only holders of limited partnership units at the close of business on the record date are entitled to notice of and to vote at the special meeting.

The affirmative vote of the holders of a majority of the outstanding limited partnership units held by the investors is required to approve the amendment to the partnership agreement and the merger agreement. All investors will be bound by the vote of the investors at the special meeting. If the amendment to the partnership agreement is not approved by the required vote, the merger agreement proposal will not be presented or considered for approval at the special meeting. PDC and its affiliates will not vote at the special meeting either as the managing general partner or with respect to any limited partnership units they own. Investors are entitled to assert appraisal rights and have the right to dissent from the merger under the West Virginia Business Corporation Act and thereby to receive a payment in cash for the fair value of their limited partnership units.

Your vote is important regardless of the number of limited partnership units you own. PDC requests that you complete and sign the enclosed proxy card and mail it promptly in the accompanying postage-prepaid envelope. You may also vote over the internet at http://www.pdcgas.com/castmyvote.cfm. If you choose to vote over the internet, you will be required to enter your Unique ID. Your Unique ID is the 8-to-10 digit number found on the bottom left of the proxy card included with the enclosed proxy statement. You may revoke any proxy that you have previously delivered prior to the special meeting by delivering a written notice to the partnership stating that you have revoked your earlier proxy or by delivering a later-dated proxy at any time prior to the special meeting. You may also revoke your proxy or change your earlier vote over the internet by following the instructions at that site. Investors who attend the special meeting may vote in person, even if they have previously delivered a signed proxy, including a proxy voted over the internet.

PDC 2002-D Limited Partnership

Darwin L. Stump

Vice President Accounting Operations

Petroleum Development Corporation,

Managing General Partner

PDC 2002-D LIMITED PARTNERSHIP

1775 Sherman Street, Suite 3000

Denver, Colorado 80203

PROXY STATEMENT
SPECIAL MEETING OF THE INVESTORS IN
PDC 2002-D LIMITED PARTNERSHIP
TO BE HELD ON OCTOBER 28, 2011

Dear Investors in PDC 2002-D Limited Partnership:

We invite you to attend the special meeting (including any adjournment or postponement of such special meeting) of the investors in PDC 2002-D Limited Partnership, a West Virginia limited partnership, which we refer to as the partnership. The special meeting will be held on October 28, 2011, at 10:00 a.m., Mountain Time. The purpose of the special meeting is for you to vote on an amendment to the partnership’s limited partnership agreement, which we refer to as the partnership agreement, and on a merger of the partnership that, if completed, will result in your receiving cash for your limited partnership units. DP 2004 Merger Sub, LLC, a Delaware limited liability company, which we refer to as the merger sub, desires to acquire the partnership. The merger sub is a direct wholly-owned subsidiary of Petroleum Development Corporation (dba PDC Energy), a Nevada corporation, which we refer to as PDC. If you and the other limited partners other than PDC and its affiliates, whom we refer to as the investors, approve the merger, the partnership will be merged with and into the merger sub, the merger sub will survive the merger and your limited partnership units will be converted into the right to receive cash in an amount equal to $4,024 per limited partnership unit, plus the sum of the amounts withheld from per unit cash distributions by the partnership from October 1, 2010 through August 31, 2011 for the partnership’s additional Codell formation development plan, less the sum of the per unit cash distributions made after August 31, 2011, as more fully described in this proxy statement.

The special committee of the board of directors of PDC, which we refer to as the special committee, on behalf of PDC in its capacity as the managing general partner of the partnership, has approved the merger agreement, has determined that the merger is advisable and in the best interests of the partnership and reasonably believes that the merger is fair to the investors, each of whom is unaffiliated with PDC.

We can complete the merger only if the amendment to the partnership agreement and the merger agreement are approved by holders of a majority of outstanding limited partnership units held by the investors. This document provides information about the amendment to the partnership agreement and the proposed merger. It also includes a copy of the merger agreement, the partnership agreement, the form of the amendment to the partnership agreement, the reserve report and statutes detailing appraisal rights in West Virginia. Please give all of this information your careful attention.

YOUR VOTE IS IMPORTANT. Whether or not you plan to attend the special meeting, please take the time to vote by completing and mailing to us the enclosed proxy card. This will not prevent you from revoking your proxy at any time prior to the special meeting or from voting your limited partnership interests in person if you later choose to attend the special meeting. You may also vote via the internet at the following web site: http://www.pdcgas.com/castmyvote.cfm. If you choose to vote over the internet, you will be required to enter your Unique ID. Your Unique ID is the 8-to-10 digit number found on the bottom left of the proxy card included with this proxy statement.

SUMMARY TERM SHEET

In this section, we highlight selected information from this proxy statement. However, we may not have included all of the information that may be important to you. To better understand the proposed amendment to the partnership agreement, the merger and the merger agreement, and for a description of the legal terms and conditions governing the merger, you should carefully read this entire proxy statement, including the appendices, which include a copy of the merger agreement, the partnership agreement and the form of the amendment to the partnership agreement. For definitions of oil and gas terms used in this document, see “Commonly Used Oil and Gas Terms.”

When this proxy statement uses the terms “PDC,” “we,” “us,” “our” or “ours” it is referring to Petroleum Development Corporation. When this proxy statement uses the term “merger sub,” it is referring to DP 2004 Merger Sub, LLC. When this proxy statement uses the term “affiliated officers” it is referring to Messrs. Bart Brookman, Gysle Shellum and Dan Amidon collectively. When this proxy statement uses the term “partnership affiliates” it is referring to PDC, merger sub and the affiliated officers collectively. When this proxy statement uses the term “partnership,” it is referring to PDC 2002-D Limited Partnership, and when it uses the term “investors” it is referring to the holders of limited partnership units of the partnership, other than PDC and its affiliates. The Agreement and Plan of Merger, dated as of June 20, 2011, which we refer to as to the merger agreement, by and among PDC, the merger sub and the partnership, is included as Appendix A to this proxy statement.

Special Meeting of Investors

The special meeting of the investors will be held on October 28, 2011, at 10:00 a.m., Mountain Time, at 1775 Sherman Street, Suite 3000, Denver, Colorado 80203. The purpose of the special meeting, and any adjournment or postponement of the special meeting, is for the investors to consider and vote on the following matters:


	•	A proposal by PDC to amend the partnership agreement, which we refer to as the amendment, in order to grant the investors an express right to vote to approve merger transactions such as the proposed merger.

	•	A proposal by PDC to approve the Agreement and Plan of Merger, dated as of June 20, 2011, which we refer to as the merger agreement, by and among the partnership, PDC and the merger sub, pursuant to which the partnership will merge with and into the merger sub, with the merger sub being the surviving entity. The merger consideration offered under the merger agreement was determined using an effective transaction date of July 1, 2011.

	•	Any proposal to adjourn or postpone the special meeting to a later date if necessary or appropriate, including an adjournment or postponement to solicit additional proxies if, at the special meeting, the number of limited partnership units present or represented by proxy and voting in favor of the approval of the merger agreement or the amendment to the partnership agreement is insufficient to approve the merger agreement or the amendment of the partnership agreement, respectively.

	•	Other business as may properly come before the special meeting.

See “The Special Meeting” beginning on page 51.

Proposed Merger Transaction


	•	Parties to the Proposed Merger Transaction.


	•	Petroleum Development Corporation. PDC, a Nevada corporation, is an independent energy company engaged in the exploration, development, production and marketing of crude oil, NGLs and natural gas. Since it began oil and gas operations in 1969, PDC has grown through drilling and development activities, acquisitions of producing natural gas and oil wells and the expansion of its natural gas marketing activities. PDC also serves as the managing general partner of 26 partnerships formed to drill, own and operate natural gas and oil wells, including PDC 2002-D Limited Partnership. PDC, in its capacity as managing general partner of the partnership, prepared this document to solicit your proxy. See “Additional Business Information — Petroleum Development Corporation.”


	•	DP 2004 Merger Sub, LLC. The merger sub is a direct, wholly-owned subsidiary of PDC and was formed as a limited liability company under the laws of the State of Delaware. The merger sub was formed on May 7, 2010 solely for the purpose of effecting the merger of PDC’s drilling partnerships. See “Additional Business Information — DP 2004 Merger Sub, LLC.”

	•	PDC 2002-D Limited Partnership. The partnership is a limited partnership formed on June 3, 2002 pursuant to the West Virginia Uniform Limited Partnership Act. The partnership was formed to drill, own and operate natural gas and oil wells and to provide the general and limited partners with tax incentives and cash flow from operations. Since the commencement of operations in 2002, the partnership has been engaged in onshore, domestic oil and natural gas exploration exclusively in the Rocky Mountain Region. PDC serves as managing general partner of the partnership. There were 1,422.11 limited and additional general partners who contributed initial capital of $29.1 million and PDC contributed $6.3 million in capital as a participant in accordance with the contribution provisions of the partnership agreement. On October 20, 2003, in accordance with the partnership agreement, all of the partnership’s additional general partners were converted to limited partners. The partnership had 1,455.26 limited partnership units outstanding as of the record date, 143.1 (or approximately 9.83%) of which were held of record by PDC or an affiliate thereof. As of the record date, there were 1,031 non-PDC registered holders. See “Additional Business Information — PDC 2002-D Limited Partnership.”


	•	The Merger. You are being asked to vote to approve the merger agreement. Pursuant to the merger agreement, the partnership will merge with and into the merger sub, with the merger sub being the surviving entity. In the event holders of less than a majority of the outstanding limited partnership units held by the investors vote to approve the amendment or the merger agreement, PDC will withdraw the offer and the merger will not proceed. See “The Merger Agreement” beginning on page 59.


	•	Merger Consideration. Upon consummation of the merger, all of the partnership’s outstanding limited partnership units (other than the limited partnership units owned by PDC or any subsidiary thereof and other than limited partnership units owned by investors who properly exercise appraisal rights) will be converted into the right to receive cash in an amount equal to $4,024 per limited partnership unit, plus the sum of the amounts withheld from per unit cash distributions by the partnership from October 1, 2010 through August 31, 2011 for the partnership’s additional Codell formation development plan, less the sum of the per unit cash distributions made after August 31, 2011, and before the transaction closes. See “Method of Determining Merger Value and Amount of Cash Offered” beginning on page 56.


	•	Components of Merger Value. The $4,024 per unit merger value assigned to the partnership was based on an effective transaction date of July 1, 2011 and calculated as follows:


	•	PDC calculated the volumes of the partnership’s proved reserves as of July 1, 2011 based on a future production curve consistent with the production curves used in the partnership’s proved reserve report as of December 31, 2010, with the addition of estimated reserves attributable to non-proven recompletion and drilling projects not included in the partnership’s proved reserve report.

	•	PDC calculated the present value of estimated future net cash flows from the partnership’s estimated production and reserves as of July 1, 2011 using (1) 100% of the arithmetic average of the five-year NYMEX futures price as of March 31, 2011 for oil, which was approximately $104.29 per barrel, less standard industry adjustments and differentials by area, and (2) 100% of the arithmetic average of the five-year NYMEX futures price as of March 31, 2011 for gas, which was approximately $5.37 per Mcf, less standard industry adjustments and differentials by area. Standard industry adjustments included:


	•	the effects of oil quality;

	•	BTU content for gas;

	•	oil and gas gathering and transportation costs; and

	•	gas processing costs and shrinkage.


	•	Those adjustments reflected assumptions about the costs to extract and process, if necessary, crude oil, natural gas liquids and natural gas and transport them to their point of sale.


	•	PDC calculated the present value of the estimated future net cash flows using before tax discount rates of 15% for proved developed producing reserves and 25% for proved developed non-producing reserves.

	•	Proved developed non-producing reserves include both Codell refracturing and Niobrara recompletion projects.

	•	Substantial capital expenditures could increase production, but given that the partnership cannot incur debt, such capital expenditures could only be made by withholding distributions over the long term.

	•	Non-proven undeveloped projects were valued at $10,000 per drilling location.


	•	See “Method of Determining Merger Value and Amount of Cash Offered” beginning on page 56.


	•	Limitations of Merger Value Calculations. The calculations of the partnership’s proved reserves of crude oil, natural gas liquids and natural gas and future net revenues from those reserves included in this document are only estimates and may be incorrect.


	•	The accuracy of any estimate is a function of:


	•	the quality of available data;

	•	engineering and geological interpretation and judgment regarding future production levels of oil, natural gas liquids and natural gas;

	•	assumptions about future quantities of recoverable oil, natural gas liquids and natural gas reserves and operating expenses related thereto;

	•	the timing of and actual level of success realized in the development of non-producing reserves;

	•	assumptions about prices for crude oil, natural gas liquids and natural gas; and

	•	assumptions about costs to extract and process, if necessary, crude oil, natural gas liquids and natural gas and to transport them to their point of sale.


	•	Since the merger value is based on assumptions about reserves, production, commodity prices and costs that may prove to be incorrect, the merger value could vary materially from the current market value of, or the price that a third party might offer for, the partnership’s estimated oil and gas reserves and from the value given to the partnership’s actual future net revenues. The assumptions used to determine the merger value might not properly reflect the value of the partnership’s assets. In that case, partners could receive less than a fair market price for their partnership interests. See “Risk Factors — The estimates of proved reserves and future net revenues considered when calculating the merger value, and underlying assumptions about future production, commodity prices and costs, may be incorrect,” “Risk Factors — The merger value might not reflect the value of the partnership’s assets,” “Risk Factors — PDC does not expect that the merger value will be adjusted for changes before the completion of the merger,” and “Risk Factors — You were not independently represented in establishing the terms of the merger.”

	•	A copy of the partnership’s reserve report as of December 31, 2010, including the assumptions used in the preparation of that report, is included as Appendix D to this proxy statement. The partnership’s financial statements as of June 30, 2011 and 2010 and for the periods then ended and as of December 31, 2010 and 2009 and for the years then ended are included as Appendix E to this proxy statement.


	•	Purpose of the Proposed Merger Transaction. Drilling partnerships are not part of PDC’s strategic plan going forward, and PDC wishes to buy them back, to the extent feasible. PDC has not established a drilling partnership since 2007 and has publicly announced a fundamental shift in its business strategy away from the partnership model to a more traditional exploration and production company model. PDC also wishes to position itself as a growth company, and consummation of the merger will allow PDC to invest further capital in the partnership’s assets on a timetable of its own choosing. In addition, the merger will result in administrative efficiencies and cost reductions in the management and operation of the properties now owned by the partnership, particularly in the areas of audit, accounting and tax services, SEC reporting, engineering services, bookkeeping, data processing, record maintenance and communication with the partners. Finally, no liquid market currently exists for the partnership’s limited partnership units, and the merger will afford investors the opportunity to cash out their investment in the partnership. See “Special Factors with Respect to the Merger — PDC’s Reasons for the Merger” and “Special Factors with Respect to the Merger — The Partnership’s Reasons for the Merger.”

Other Important Considerations


	•	Conflicts of Interest.


	•	In considering the recommendation with respect to the merger of the special committee, on behalf of PDC in its capacity as managing general partner of the partnership, the investors should be aware that PDC has interests in the merger that are different from, or in addition to, the interests of the investors generally. PDC, as managing general partner of the partnership, has a duty to manage the partnership in the best interests of the limited partners of the partnership. However, PDC also has a duty to operate its business for the benefit of its shareholders. Consequently, PDC’s duties to its shareholders may conflict with its duties to the investors.

	•	In addition, the members of the board of directors of PDC have a duty to cause PDC to manage the partnership in the best interests of the limited partners of the partnership. However, members of the board of directors of PDC also have a duty to operate PDC’s business for the benefit of its shareholders, and board members who are also officers of PDC have a duty to operate PDC’s business in PDC’s best interests. Consequently, the duties of the members of the board of directors of PDC to the investors may conflict with the duties of those members to PDC and PDC’s shareholders.

	•	PDC and its board of directors have attempted to formally address the conflicts inherent in the relationships among PDC, the partnership and the officers and directors of PDC by forming a special committee of the board of directors consisting of four non-employee members of PDC’s board. However, because each of the members of the special committee is also a member of PDC’s board of directors, an inherent conflict continues to exist with respect to each member’s duties to the investors in his capacity as a member of the special committee, on the one hand, and such member’s duties to the shareholders of PDC in his capacity as a member of PDC’s board of directors, on the other hand.


	•	See “Special Factors with Respect to the Merger — Conflicting Duties of PDC, Individually and as the General Partner” beginning on page 42.


	•	Fairness of the Transaction.


	•	*Special Committee.* The special committee, on behalf of PDC in its capacity as the managing general partner of the partnership, has approved the merger agreement, has determined that the merger is advisable and in the best interests of the partnership and reasonably believes that the merger is fair to the investors, each of whom is unaffiliated with PDC. In reaching its conclusion as to the fairness of the transaction, the special committee also considered the procedural and substantive fairness of the transaction to the unaffiliated investors. See “Special Factors with Respect to the Merger — The Partnership’s Discussion of the Fairness of the Merger; Recommendation of the Special Committee on Behalf of the Partnership” beginning on page 26.


	•	*Partnership Affiliates.* The rules of the SEC require each of the partnership affiliates to express a belief as to the substantive and procedural fairness of the proposed merger to the unaffiliated holders of limited partnership interests. The views of the partnership affiliates with respect to the fairness of the merger to the

unaffiliated holders of limited partnership interests are not, and should not be construed as, a recommendation to any unaffiliated holder of limited partnership interests as to how that unaffiliated holder of limited partnership interests should vote on the proposal to approve the merger agreement. Each of the partnership affiliates believes the merger is procedurally and substantively fair to the unaffiliated holders of limited partnership interests. See “Special Factors with Respect to the Merger — Position of the Partnership Affiliates as to the Fairness of the Merger to the Unaffiliated Holders of Limited Partnership Interests” beginning on page 23.


	•	Recommendation Regarding the Proposed Merger Transaction. The special committee encourages you to vote FOR the proposals to approve the amendment and the merger agreement and FOR any proposal to adjourn or postpone the special meeting to a later date, including an adjournment or postponement to solicit additional proxies if, at the special meeting, the number of limited partnership units present or represented by proxy and voting in favor of the approval of the merger agreement or the amendment to the partnership agreement is insufficient to approve the merger agreement or the amendment to the partnership agreement, respectively. See “Special Factors with Respect to the Merger — The Partnership’s Discussion of the Fairness of the Merger; Recommendation of the Special Committee on Behalf of the Partnership.”

	•	Opinion of the Special Committee’s Financial Advisor.


	•	On June 11, 2011, Houlihan Lokey Financial Advisors, Inc., which we refer to as Houlihan Lokey, rendered its oral opinion to the special committee (which was subsequently confirmed in writing by delivery of Houlihan Lokey’s written opinion dated the same date) to the effect that, as of June 11, 2011, the consideration to be received by the unaffiliated holders of limited partnership interests in the proposed merger pursuant to the merger agreement was fair to such unaffiliated holders of limited partnership interests from a financial point of view. For purposes of its opinion, Houlihan Lokey defined the unaffiliated holders of limited partnership interests as the holders of limited partnership interests in the partnership other than PDC and its affiliates.


	•	Houlihan Lokey’s opinion was directed to the special committee and only addressed the fairness, from a financial point of view, to the unaffiliated holders of limited partnership interests of the consideration to be received by the unaffiliated holders of limited partnership interests in the proposed merger pursuant to the merger agreement, and did not address any other aspect or implication of the proposed merger. The summary of Houlihan Lokey’s opinion in this proxy statement is qualified in its entirety by reference to the full text of its written opinion, which is included as Appendix B to this proxy statement and sets forth the procedures followed, assumptions made, qualifications and limitations on the review undertaken and other matters considered by Houlihan Lokey in preparing its opinion. However, neither Houlihan Lokey’s written opinion nor the summary of its opinion and the related analyses set forth in this proxy statement are intended to be, and they do not constitute, advice or a recommendation to any holder of limited partnership interests as to how such limited partner should act or vote with respect to any matter relating to the merger. See “Special Factors with Respect to the Merger — Opinion of the Special Committee’s Financial Advisor” beginning on page 28.


	•	Effects of the Transaction. The merger will involve the merger of the partnership with and into the merger sub, an exchange of cash consideration for the limited partnership units held by the investors, and all of PDC’s interest in the partnership (including, without limitation, its managing general partner interest and all limited partnership units held by PDC or any of its affiliates) shall be extinguished. As a result of the merger, the investors will have no continuing interest in the partnership. Following the merger, there will be no trading market for the limited partnership units, and no further distributions will be paid to the former investors. In addition, following the consummation of the merger, the registration of any limited partnership units under the Securities Exchange Act of 1934, as amended, will be terminated. Upon completion of the merger, the merger sub shall be the surviving entity, the partnership will cease to exist as a separate business entity, and PDC shall hold all of the interests in the merger sub. See “Special Factors with Respect to the Merger — Effects of the Merger” beginning on page 42.


	•	Appraisal Rights. Whether the investors vote to approve or reject the amendment and/or the merger agreement proposals, you as an investor will be bound by the vote. As a result, if the amendment and the

merger agreement are approved by the investors, all investors will be required to exchange their limited partnership units for the cash payment described above, including those investors who voted against approving the merger agreement, subject to the valid exercise of appraisal rights. See “Rights of Dissenting Investors” beginning on page 62.


	•	Material U.S. Federal Income Tax Consequences. The exchange by an investor of limited partnership units for cash pursuant to the merger will be a taxable transaction for U.S. federal income tax purposes. The effects of the merger may be different for each investor. See “Special Factors with Respect to the Merger — Material U.S. Federal Income Tax Consequences” beginning on page 44. You are urged to consult your own tax advisor to determine all of the relevant federal, state and local tax consequences of the merger particular to you. The discussion in this proxy statement is not intended as a substitute for careful tax planning, and you must depend upon the advice of your own tax advisor concerning the effects of the merger.

Questions and Answers About the Proposed Merger Transaction

• WHAT WILL INVESTOR APPROVAL OF THE PROPOSED TRANSACTION MEAN FOR ME?

If the holders of a majority of the outstanding limited partnership units held by the investors vote to approve both the amendment to the partnership agreement and the merger agreement, upon consummation of the merger, each limited partnership unit (other than the limited partnership units owned by PDC or any subsidiary thereof and other than limited partnership units owned by investors who properly exercise appraisal rights as described below) will be converted into the right to receive cash in an amount equal to $4,024 per limited partnership unit, plus the sum of the amounts withheld from per unit cash distributions by the partnership from October 1, 2010 through August 31, 2011 for the partnership’s additional Codell formation development plan, less the sum of the per unit cash distributions made after August 31, 2011, and before the transaction closes (proportionally adjusted for partial limited partnership units), as more fully described in this proxy statement under the heading “Method of Determining Merger Value and Amount of Cash Offered — Components of Merger Value.” If holders of less than a majority of the outstanding limited partnership units held by the investors vote to approve either the amendment to the partnership agreement or the merger agreement, PDC will withdraw its offer, each investor will continue to be an investor in the partnership, and the partnership will continue its normal business operations. See “Special Factors with Respect to the Merger — Effects of the Merger.”

A regular cash distribution will be made by the partnership in August 2011 based on the partnership’s production through June 2011. The merger value was determined based on data projected as of July 1, 2011. Accordingly, if the merger is approved by the investors and completed, investors will be entitled to receive cash in an amount equal to $4,024 per limited partnership unit, plus the sum of the amounts withheld from per unit cash distributions by the partnership from October 1, 2010 through August 31, 2011 for the partnership’s additional Codell formation development plan, less the sum of the per unit cash distributions made after August 31, 2011.


•	*WHY IS PDC MAKING AN OFFER TO ACQUIRE THE PARTNERSHIP AT THIS TIME?*


	•	Future natural gas prices are uncertain because low-cost shale plays, particularly the Marcellus shale, may set national prices going forward. These low-cost shale plays, which have experienced a large increase in development in recent years, have added significant proved reserves and increased production primarily in the eastern portion of the United States where demand is the highest. These reserves now represent a much larger part of overall natural gas reserves and production in the United States and have the potential to affect the variability of open market pricing more significantly than in the past, along with a potential oversupply situation in a downturned economy. As a result of lower natural gas prices, the high natural gas hedging prices which PDC has achieved for the partnership during the last several years are not available at this time for future periods. PDC expects that lower realized natural gas prices, declining production, and any withholdings for the additional Codell formation development plan will result in reduced per unit distributions in the future. The partnership’s aggregate cash distributions per limited partnership unit for the twelve months ended June 30, 2011 were $50. However cash flows available for distribution per limited partnership unit were $66, thus creating an decrease in the “— due to Managing General Partner” account.

PDC estimates the partnership’s aggregate cash flows available for distribution per limited partnership unit for the twelve months ending March 31, 2012 will be $327, however distributions are expected to be minimal (approximately $50 per unit) due to cash flows available for distribution being used to repay the “— due to Managing General Partner” and to partially fund the partnership’s additional Codell formation development plan. This estimate is based on the twelve month production period beginning in April 1, 2011 and ending in March 31, 2012. This estimated cash flows available for distribution is approximately $261 more than the aggregate cash distributions for the twelve months ended June 30, 2011. The increase in cash flows available for distributions is expected to result primarily from a reduction in general and administrative expenses in addition to decreases in operating expenses as a result of normal production declines and decreases in workover costs for environmental and maintenance projects. The estimate does not assume any incremental revenue or take into account additional refracturing or the withholding of distributions to develop proved undeveloped reserves. PDC believes that the estimates, assumptions and considerations made in calculating the estimated aggregate cash flows available for distribution for the twelve months ending March 31, 2012, are reasonable. The projections summarized below were also provided to Houlihan Lokey, the special committee’s financial advisor.


	•	The following table shows the financial statement line items used to determine cash flows available for distribution. Certain non-cash items were excluded because they have no effect on the cash distributed to limited partners:


	Twelve Months Ended		Twelve Months Ending
	June 30, 2011 (Actual)		March 31, 2012 (Estimated)

Revenue(1)	$	1,350,561	$	1,251,000
Realized derivative gains (losses)(2)		124,953		8,000
Gross revenues		1,475,514		1,259,000
Operating expenses(3)		585,375		431,000
Production taxes(4)		65,719		64,000
General and administrative expenses(5)		703,534		170,000
Total costs		1,354,628		665,000
Net cash flows available for distribution(a)	$	120,886	$	594,000
General partner cash flows		24,177		118,800
Limited partner cash flows	$	96,709	$	475,200
Limited partnership units		1455.26		1455.26
Cash flows available for distribution per limited partnership unit(b)	$	66	$	327


(a)		Cash flows available for distribution represent amounts prior to any withholdings for the well refracturing program. Any amounts withheld for the refracturing program will be added back to the purchase price upon closing of the merger.


(b)		Cash flows available for distribution per limited partnership unit for the twelve months ended June 30, 2011 were $66 per limited partnership unit during this twelve month period. Due to the normal two-month delay between production and distribution and the delay in offsetting general and administrative costs against revenues, actual cash distributions for the twelve months ended June 30, 2011 were $50 per limited partnership unit. The amount “— due to Managing General Partner” increased due to PDC’s policy of delaying the offset of certain large expenditures against revenues until sufficient revenues are available. For the twelve months ending March 31, 2012 cash flows available for distribution are estimated to be $327 per limited partnership unit. However distributions are expected to be minimal (less than $50 per unit) due to the use of these cash flows to reduce the “— due to Managing General Partner” and to partially fund the partnership’s additional Codell formation development plan.


*(1)*	*Operating Revenue*


	•	PDC estimates that the partnership will generate $1,251,000 in revenues during the twelve months ending March 31, 2012. The partnership generated $1,350,561 in revenues during the twelve months ended June 30, 2011.


	•	The anticipated decrease in the partnership’s revenues of $99,561 is primarily expected to result from decreases in production discussed below, partially offset by the anticipated increase in realized prices.


	•	NYMEX forward pricing curves as of March 31, 2011 were used to calculate estimated revenue. The revenue for the twelve months ended June 30, 2011 was based on average pricing received for the period. The average forward strip price used in the March 31, 2012 projection was $7.11 per Mcfe compared to the average sales price realized of $5.49 per Mcfe during the twelve months ended June 30, 2011.


	•	PDC estimates that the partnership’s production will be 176,000 Mcfe during the twelve months ending March 31, 2012. The partnership produced 246,126 Mcfe during the twelve months ended June 30, 2011. The anticipated decrease in production of 70,126 Mcfe is expected to result from reduced economics for several of the Partnership’s wells in addition to normal production declines.


	•	The estimated production was obtained from an internally generated reserve report that was based on the partnership’s 2010 year-end reserve report updated for NYMEX forward pricing curves as of March 31, 2011. The partnership’s 2010 year-end reserve report was prepared by Ryder Scott, the partnership’s independent reserve engineers, and utilized information provided by management.


*(2)*	*Realized Derivative Gains*


	•	PDC estimates that the partnership will generate $8,000 in net realized gains during the twelve months ending March 31, 2012. The partnership generated $124,953 in net realized gains during the twelve months ended June 30, 2011.


	•	The expected decrease in net realized gains of $116,953 is primarily expected to result from the fact that the partnership’s future production is hedged at a significantly lower price for the remaining positions when compared to the twelve months ended June 30, 2011.


	•	Forward pricing curves as of March 31, 2011 were used to calculate realized gains and losses based on current derivative positions which settle between April 2011 and March 2012.


*(3)*	*Operating Expenses*


	•	PDC estimates that the partnership’s operating expenses will be $431,000 during the twelve months ending March 31, 2012, as compared to $585,375 for the twelve months ended June 30, 2011. Projections based on the internally generated reserve report, as described above, were used to calculate operating expenses for the twelve months ending March 31, 2012. During the twelve months ended June 30, 2011, the partnership incurred significant workover costs for environmental and maintenance projects, which increased operating costs by approximately $155,000. There are currently no workover costs planned for the twelve months ending March 31, 2012.


*(4)*	*Production Taxes*


	•	PDC estimates that the partnership’s total production tax expenses will be $64,000 during the twelve months ending March 31, 2012, as compared to $65,719 during the twelve months ended June 30, 2011. Estimated production taxes were based on current tax rates, as PDC does not anticipate a significant change in rates through March 31, 2012. These rates were applied to the calculated revenue to arrive at the total production tax expense.


*(5)*	*General and Administrative Expenses*


	•	PDC estimates that the partnership’s total general and administrative expense will be $170,000 during the twelve months ending March 31, 2012, as compared to $703,534 during the twelve months ended June 30, 2011. The partnership’s general and administrative expenses consist of audit, income tax preparation and outside consultant fees, among other expenses. The anticipated decrease of $533,534 in general and administrative costs is expected to result from nonrecurring professional fees due to the partnership’s compliance catch-up efforts. The projected general and administrative costs for the period ending March 31, 2012 were based on internal estimates of expected recurring costs.

Regulatory, Industry and Economic Factors


	•	In making its estimates, PDC assumed that there would be no new federal, state or local regulations of the portions of the energy industry in which the partnership operates, and no new interpretations of existing regulations that would be materially adverse to the partnership’s business during the twelve months ending March 31, 2012.


	•	In making its estimates, PDC also assumed no major adverse changes in the upstream oil and gas industry or in general economic conditions during the twelve months ending March 31, 2012.

This prospective financial information was not prepared with a view toward compliance with published guidelines of the Securities and Exchange Commission or the guidelines established by the American Institute of Certified Public Accountants for the preparation and presentation of prospective financial information. The prospective financial information included in this proxy statement has been prepared by, and is the responsibility of, PDC’s management. PricewaterhouseCoopers LLP has not examined, compiled or performed any procedures with respect to such prospective financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance with respect thereto. The PricewaterhouseCoopers LLP report included in this proxy relates to the partnership’s historical financial information. It does not extend to the prospective financial information and should not be read to do so.


•	*WHAT EFFECT WILL THE TRANSACTION HAVE ON MY DISTRIBUTION CHECKS?*

You will continue to receive distribution checks until the transaction is approved by the investors and completed. The merger value was determined based on data projected as of July 1, 2011. Accordingly, if approved by the investors and completed, you will be entitled to receive cash in an amount equal to $4,024 per limited partnership unit, plus the sum of the amounts withheld from per unit cash distributions by the partnership from October 1, 2010 through August 31, 2011 for the partnership’s additional Codell formation development plan, less the sum of the per unit cash distributions made after August 31, 2011.

We intend to mail you a check for this transaction within 30 days after the merger is completed. Checks will be mailed to the same addresses to which monthly distribution checks are mailed. If the transaction is not approved or completed, you will continue to receive your distributions as you have in the past. See “Distribution of Cash Payments.”


•	*WHAT EFFECT WILL THE TRANSACTION HAVE ON MY K-1?*

In or before February 2012, you will receive your 2011 K-1 reflecting 2011 taxable income. If the transaction is approved, you will receive your final 2011 K-1 in or before 2012, and afterwards, investors will have no continuing interest in the partnership and the merger will eliminate the investors’ Schedule K-1 tax reports in the partnership for tax years after the merger occurs. This is expected to simplify the investors’ individual tax return preparation and reduce preparation costs. See “Special Factors with Respect to the Merger — Material U.S. Federal Income Tax Consequences.”


•	*WHAT IS THE STRUCTURE OF THE PROPOSED MERGER TRANSACTION?*

If the merger transaction is approved by holders of a majority of outstanding limited partnership units held by the investors, the partnership will be merged with and into DP 2004 Merger Sub, LLC, a Delaware limited liability company, which we refer to as the merger sub. The merger sub is a wholly-owned subsidiary of PDC. Upon completion of the merger, the merger sub will be the surviving entity, the separate existence of the partnership as a business entity will cease, and PDC will hold all of the equity interests in the merger sub. As consideration for their

limited partnership units, the investors will be entitled to receive a cash payment in an amount equal to $4,024 per limited partnership unit, plus the sum of the amounts withheld from per unit cash distributions by the partnership from October 1, 2010 through August 31, 2011 for the partnership’s additional Codell formation development plan, less the sum of the per unit cash distributions made after August 31, 2011 and before the transaction closes, as more fully described in this proxy statement under the heading “Method of Determining Merger Value and Amount of Cash Offered — Components of Merger Value.”

In order for the investors to have the express right to consider the proposed merger agreement, an amendment to the partnership agreement must first be approved by the holders of a majority of outstanding limited partnership units held by the investors at a special meeting of the investors. See “The Special Meeting.” Copies of the merger agreement, the partnership agreement and the form of the amendment to the partnership agreement are included as Appendices A, F and G to this proxy statement, respectively.


•	*HOW DOES THE PRICING VOLATILITY ADJUSTMENT MECHANISM WORK?*

As a result of significant volatility in commodity prices in recent years, commodity prices can increase and decrease by substantial amounts between the date a merger agreement for an acquisition is entered into and the date the definitive proxy statement is mailed to investors. To attempt to account for such volatility and to align the amount of consideration offered to investors at the date of mailing the definitive proxy statements with the commodity prices at such date, the merger agreement provides a mechanism, which we refer to as the pricing volatility adjustment mechanism, whereby the merger consideration offered to investors can increase, but not decrease, between (i) the date of entering into the merger agreement and (ii) the date of filing the definitive proxy statement with the SEC. The merger agreement does not provide a mechanism to adjust the merger value for changes in commodity prices between the date of filing the definitive proxy statement and the consummation of the merger. As a result, PDC does not expect that the merger value will change to reflect any general changes in oil or gas prices, any other matter generally affecting the oil and gas industry, or any revisions to, or new information regarding, the partnership’s reserve, production, price or cost estimates occurring after the date of filing the definitive proxy statement and prior to the closing date of the merger (other than for the addition of the sum of the amounts withheld from per unit cash distributions by the partnership from October 1, 2010 through August 31, 2011 for the partnership’s well refracturing plan and the subtraction of the per unit cash distributions made after August 31, 2011). See “Risk Factors — PDC does not expect that the merger value will be adjusted for changes before the completion of the merger.” The following table provides examples highlighting how the pricing volatility adjustment mechanism works in connection with certain hypothetical changes in the arithmetic average of the five year NYMEX futures prices, which we refer to as the “5-yr NYMEX avg.”, for oil and gas. As shown in the last row in the table below, no matter how much commodity prices decrease, the pricing volatility adjustment mechanism will not decrease the merger consideration offered to investors under the merger agreement.

Pricing Volatility Adjustment Mechanism
Per Unit Adjustments of PDC 2002-D Limited Partnership


					Hypothetical 5-
			5-yr. NYMEX		yr. NYMEX		Hypothetical 5-yr.
			avg. per Mcf for		avg. per Bbl for		NYMEX avg. per
	5-yr. NYMEX avg.		gas used to		oil on the date		Mcf for gas on the		Increased cash
	per Bbl for oil used		calculate initial		prior to the		date prior to the		consideration per
	to calculate initial		merger value		filing of the		filing of the		limited partnership
	merger value (as of		(as of March 31,		definitive proxy		definitive proxy		unit, if any, offered to
	March 31, 2011)		2011)		statement		statement		investors

Scenario 1(a)	$	104.29	$	5.37	$	109.29	$	5.37	$	275
Scenario 2(b)	$	104.29	$	5.37	$	116.29	$	5.37	$	550
Scenario 3(c)	$	104.29	$	5.37	$	104.29	$	5.87	$	200
Scenario 4(d)	$	104.29	$	5.37	$	109.29	$	4.87		75
Scenario 5(e)	$	104.29	$	5.37	$	114.29	$	4.87	$	350
Scenario 6(f)	$	104.29	$	5.37	$	94.29	$	4.37		N/A	(g)


(a)		Assumes the 5 yr. NYMEX avg. for oil on the date prior to the date of the filing of the proxy statement exceeds the NYMEX avg. for oil as of March 31, 2011 by $5.00 per Bbl and the 5 yr. NYMEX avg. for gas remains constant during this same period.


(b)		Assumes the 5 yr. NYMEX avg. for oil on the date prior to the date of the filing of the proxy statement exceeds the NYMEX avg. for oil as of March 31, 2011 by $12.00 per Bbl and the 5 yr. NYMEX avg. for gas remains constant during this same period.

(c)		Assumes the 5 yr. NYMEX avg. for gas on the date prior to the date of the filing of the proxy statement exceeds the NYMEX avg. for gas as of March 31, 2011 by $0.50 per Mcf and the 5 yr. NYMEX avg. for oil remains constant during this same period.

(d)		Assumes the 5 yr. NYMEX avg. for oil on the date prior to the date of the filing of the proxy statement exceeds the NYMEX avg. for oil as of March 31, 2011 by $5.00 per Bbl and the 5 yr. NYMEX avg. for gas decreases by $0.50 per Mcf during this same period.

(e)		Assumes the 5 yr. NYMEX avg. for oil on the date prior to the date of the filing of the proxy statement exceeds the NYMEX avg. for oil as of March 31, 2011 by $10.00 per Bbl and the 5 yr. NYMEX avg. for gas decreases by $0.50 per Mcf during this same period.

(f)		Assumes the 5 yr. NYMEX avg. for oil as of March 31, 2011 exceeds the 5-yr. NYMEX avg. for oil on the date prior to the date of the filing of the proxy statement by $10.00 per Bbl and the NYMEX avg. for gas as of March 31, 2011 exceeds the 5-yr. NYMEX avg. for gas on the date prior to the date of the filing of the proxy statement by $1.00 per Mcf.

(g)		No change in merger consideration offered to investors.


•	*WHEN AND WHERE WILL THE SPECIAL MEETING TAKE PLACE?*

The special meeting is scheduled to take place at 1775 Sherman Street, Suite 3000, Denver, Colorado 80203 on October 28, 2011 at 10:00 a.m. local time. See “The Special Meeting — Date, Time and Place.”


•	*HOW DO I VOTE?*

Only holders of limited partnership units at the close of business on the record date are entitled to notice of and to vote at the special meeting. Each such investor will be entitled to one vote for each limited partnership unit held (or a fractional vote proportional to his interest for interests of less than one limited partnership unit) on all matters to be voted upon at the special meeting. All investors may vote by submitting a proxy by mail or via the internet. Investors are also entitled to attend and vote at the special meeting in person. See “The Special Meeting — Voting Your Limited Partnership Units.”


•	*WILL I BE BOUND BY THE MAJORITY VOTE OF THE INVESTORS?*

Yes. Whether the investors vote to approve or reject the amendment and/or the merger agreement proposals, you as an investor will be bound by the vote. As a result, if the amendment and the merger agreement are approved by the investors, all investors will be required to exchange their limited partnership units for the cash payment described above, including those investors who voted against approving the merger agreement, subject to the valid exercise of appraisal rights, as described below. Alternatively, if the amendment or the merger agreement is not approved by the investors, no limited partnership units will be exchanged for the cash payment, the partnership will continue its normal business operations, and the investors will continue to hold their investment in the partnership. See “Special Factors with Respect to the Merger — Alternatives to the Merger — Comparison of the Merger to Tender Offer” and “Rights of Dissenting Investors.”


•	*DO I HAVE DISSENTERS’ RIGHTS?*

Yes. Under West Virginia law, you have the right to dissent from the merger and demand appraisal rights. The West Virginia statutory scheme is very complicated. Failure to follow the statutory provisions precisely may result in your loss of your appraisal rights under West Virginia law. See “Rights of Dissenting Investors,” below. We present the West Virginia statutory provisions relating to appraisal rights in their entirety in Appendix C to this document. Please read this document and Appendix C carefully.


•	*WHAT DO I NEED TO DO NOW?*

Whether or not you intend to attend the special meeting in person, you should carefully review this proxy statement, indicate on the proxy card how you wish to vote and sign and return the card in the enclosed return envelope as soon as possible so that, if you do not attend personally, you will be represented by proxy at the special meeting. You may also vote via the internet at the following web site: http://www.pdcgas.com/castmyvote.cfm. If you choose to vote over the internet, you will be required to enter your Unique ID. Your Unique ID is the 8-to-10 digit number found on the bottom left of the proxy card included with this proxy statement. See “The Special Meeting — Voting Your Limited Partnership Units.”


•	*WHAT DO I DO IF I WANT TO CHANGE MY VOTE?*

Just mail a later-dated, signed proxy card or other instrument revoking your proxy so that it is received at the executive offices of the partnership by the time of the special meeting. Investors may also change their vote by attending the special meeting and voting in person. If you choose to revoke your proxy that you had earlier mailed to PDC or if you would like to vote a new proxy, please send a new proxy card (dated as of the date you changed your vote) to Darwin Stump, PDC’s Vice President Accounting Operations, 1775 Sherman Street, Suite 3000, Denver, Colorado 80203. If you cast your vote via the internet at the web site specified above, you may also revoke or change your earlier vote by following the instructions at the web site. In addition, if you voted by proxy card, you may change your vote via the internet at the web site specified above. Likewise, if you voted via the internet, you may change your vote by submitting a later-dated proxy card. See “The Special Meeting — Voting Your Limited Partnership Units — Changing Your Vote.”


•	*WHEN IS THE PROPOSED TRANSACTION EXPECTED TO BE COMPLETED?*

We intend to complete the proposed transaction as quickly as possible following investor approval, and expect to do so on or before December 15, 2011. See “The Merger Agreement — Termination of the Merger and the Merger Agreement.”


•	*WHAT ARE THE U.S. FEDERAL INCOME TAX CONSEQUENCES OF THE PROPOSED TRANSACTION TO ME?*

The exchange by an investor of limited partnership units for cash pursuant to the merger will be a taxable transaction for U.S. federal income tax purposes. The effects of the merger may be different for each investor. See “Special Factors with Respect to the Merger — Material U.S. Federal Income Tax Consequences.”

Neither the partnership nor PDC has obtained an opinion of tax counsel with respect to the federal income tax effects of the proposed transaction. We urge you to consult with your tax advisor for a full understanding of the tax consequences of the proposed transaction to you.


•	*WHO CAN HELP ANSWER MY QUESTIONS?*

For additional information about the proposed transaction, including information about how to complete and return your proxy card or how to vote over the internet, please contact PDC at 877-395-3228, or email PDC at pdcgas@pdcgas.com. See “The Special Meeting — Solicitation of Proxies and Costs.”

SPECIAL FACTORS
WITH RESPECT TO THE MERGER

General

The board of directors of PDC, on behalf of PDC individually, the special committee of the board of directors of PDC, on behalf of PDC in its capacity as the managing general partner of the partnership, and PDC, as sole member of the merger sub, have approved the merger agreement providing for the merger of the partnership with and into the merger sub. The merger sub, a wholly-owned subsidiary of PDC, will be the surviving entity in the merger, and upon completion of the merger, the separate existence of the partnership will terminate and the investors will receive cash in the amount of $4,024 per limited partnership unit, plus the sum of the amounts withheld from per unit cash distributions by the partnership from October 1, 2010 through August 31, 2011 for the partnership’s additional Codell formation development plan, less the sum of the per unit cash distributions made after August 31, 2011 and before the transaction closes. In addition, the special committee of the board of directors of PDC, on behalf of PDC in its capacity as the managing general partner of the partnership, has approved the amendment to the partnership agreement to provide the investors with an express right to vote on the proposed merger.

Background of the Merger

Since 2006, PDC’s board of directors has from time to time engaged with PDC’s senior management in strategic reviews and evaluations of opportunities to achieve long-term strategic goals and enhance stockholder value. Beginning in 2006, PDC began evaluating the possibility of buying out the investors in certain of its limited partnerships through mergers, which did not include an evaluation of the partnership. PDC’s primary reasons for considering such a series of merger transactions are described below under “— PDC’s Reasons for the Merger.” In January 2007, PDC acquired, through merger, 44 non-SEC reporting limited partnerships for an aggregate of approximately $58.8 million.

On June 2, 2008, Dan Amidon, PDC’s General Counsel, and Eric Stearns, PDC’s former Executive Vice President, began discussions with Houlihan Lokey about its serving as the financial advisor to the to-be-formed special committee with respect to the acquisition of certain pre-2002 limited partnerships, but PDC determined not to pursue a transaction at that time.

In August 2008, PDC and its board of directors attempted to formally address the conflicts inherent in the relationships among PDC, its limited partnerships and the officers and directors of PDC (as more fully described below under the heading “— Conflicting Duties of PDC, Individually and as the General Partner”) by forming a special committee of PDC’s board of directors (consisting of four non-employee members of PDC’s board, namely Anthony J. Crisafio, Larry Mazza, David C. Parke and Jeffrey C. Swoveland), which we refer to as the special committee. At such time, neither PDC nor the special committee specifically proposed or considered PDC’s acquisition of the partnership by merger. The special committee was authorized, among other things:


	•	to act on behalf of PDC’s board in representing the interests of the limited partnerships and their investors with respect to all matters relating to a merger or any related or alternative transactions thereto; and

	•	to exercise all lawfully delegable powers of PDC’s board (acting in its capacity as the governing decision-making body of the managing general partner on behalf of the limited partnerships) to take any and all actions and to make any and all decisions relating to a merger or any related or alternative transactions thereto, including without limitation, the consideration, evaluation, negotiation, rejection or acceptance thereof, all on behalf of the limited partnerships, and as the special committee deemed to be advisable and in the best interests of the limited partnerships and their investors, and to make the disclosures and filings required by Schedule 13e-3 on behalf of the board of directors of PDC, in its capacity as managing general partner of the limited partnerships, with respect to the corresponding going-private transaction.

Also in August 2008, the special committee retained Buchanan Ingersoll & Rooney PC, which we refer to as Buchanan Ingersoll, as separate legal counsel to advise it in connection with any proposed mergers. The special committee and Buchanan Ingersoll discussed the potential for various partnership merger transactions and the legal issues in connection with such transactions generally, but no specific partnerships were identified as candidates for merger at that time.

In the fall of 2009, PDC’s senior management for the first time began specifically considering which partnerships should be repurchased by PDC. The five partnerships being considered by PDC’s management for repurchase at that time were PDC 2005-A Limited Partnership, a West Virginia limited partnership (“2005-A”), PDC 2005-B Limited Partnership, a West Virginia limited partnership (“2005-B”), Rockies Region Private Limited Partnership, a West Virginia limited partnership (“RRPLP” and together with 2005-A and 2005-B, the “2005 partnerships”), as well as PDC 2004-A Limited Partnership, a West Virginia limited partnership (“2004-A”), and PDC 2004-D Limited Partnership, a West Virginia limited partnership (“2004-D”). PDC’s management, however, never formally proposed repurchasing any partnerships to the board of directors of PDC or to the special committee in 2009, and in mid-October of that year, PDC’s management informed the board of directors that the project had been suspended. The primary factor in management’s decision not to move forward was the fact that limited partners of the partnerships being considered for repurchase (except for RRPLP) held a right to put their limited partnership units, up to a certain amount, back to PDC at a price equal to 4.0x the per unit cash distributions from production for the most recent 12-month period (the “4.0X Put Right”). Although the partnership agreement of RRPLP did not provide limited partner investors a 4.0X Put Right in RRPLP, PDC’s management believed that the limited partners of RRPLP would still expect a repurchase price equal to 4.0x the per unit cash distributions from production for the most recent 12-month period (the “4.0x Put Expectation”). On August 31, 2009, the 4.0X Put Right value for the partnership was $3,938 per unit. Each of the partnerships being considered for repurchase had recorded higher cash distributions from production in the prior 12 months than were anticipated going forward due to a reduction in realized gains on derivative transactions, as well as expected lower realized natural gas prices and declining production, which resulted in a PDC senior management conclusion that an offer that would provide an acceptable rate of return to PDC would not be accepted by limited partners of the limited partnerships being considered for repurchase.

In late January 2010, PDC’s senior management re-initiated their evaluation of potential partnership repurchases by PDC. During this re-evaluation process, PDC’s management initially focused on seven partnerships, consisting of the 2005 partnerships and 2004-A, 2004-D, PDC 2004-B Limited Partnership, a West Virginia limited partnership (“2004-B”) and PDC 2004-C Limited Partnership, a West Virginia limited partnership (“2004-C” and together with 2004-A, 2004-B and 2004-D, the “2004 partnerships”).

On February 18, 2010, Richard McCullough, PDC’s Chairman and Chief Executive Officer, indicated to analysts during PDC’s Analyst Day presentation that PDC intended to initiate a three-year plan to acquire limited partnerships for which PDC serves as managing general partner.

On February 24, 2010, the special committee confirmed that it would continue to retain Buchanan Ingersoll as its legal advisor in connection with any proposed mergers. Also on February 24, 2010, Mr. Amidon contacted the special committee and Buchanan Ingersoll regarding the re-initiation of the process by which PDC would propose to acquire certain of the limited partnerships for which PDC serves as managing general partner, although no specific partnerships were discussed at that time.

At the beginning of March 2010, PDC’s management determined to proceed only with a proposal regarding the four 2004 partnerships. The decision to consider only the 2004 and 2005 partnerships, as well as the decision to proceed only with the four 2004 partnerships and not with other partnerships, including the partnership, that PDC serves as managing general partner, was based at that time as well as when partnership purchases were considered in prior years, primarily on PDC’s analysis of the following factors:


	•	The more recent partnerships were still experiencing normal steep production declines and it was believed they could not be economically acquired in light of the limited partners’ 4.0X Put Right and the 4.0x Put Expectation.

	•	Generally, the older the partnership, the better the economics for a refracturing, and also the more opportunity for faster production increases. PDC believes that well refracturing in the Codell formation of the Wattenberg Field wells, which may provide additional reserve development and production, optimally occurs five to ten years after the initial well completion. PDC has found that such refracturings generally increase the production rate and recoverable reserves for these wells. On average, the production resulting from PDC’s prior Codell well refracturings has achieved the modeled economics. The fact that the 2004 partnerships’ wells would be six years old in 2011 and therefore would fall within the time frame that PDC


		believes is optimal to conduct well refracturings was one of the primary factors in PDC’s decision to repurchase the 2004 partnerships at this time. However, the estimated value associated with the well refracturing was included in the calculation of the per unit merger value.


	•	Under SEC rules, a merger proxy may only be filed by PDC if the partnership being considered for repurchase is current in its SEC financial reporting requirements. The 2004 partnerships were the oldest partnerships which were current in their SEC financial reporting requirements.

	•	Large derivative gains reflected in 2009 and the first five months of 2010 partnership distributions created a disincentive to PDC to increase the number of partnerships included in the offer, in light of the limited partners’ 4.0X Put Right, when compared to the potential PDC offer amounts which are determined primarily on future lower hedges and pricing.

	•	Potential alternative capital uses also influenced PDC’s decision regarding the number of partnerships proposed for merger. A higher rate of return may have been possible through alternative investments later in the year through potential future acquisitions or drilling opportunities.

	•	Capital availability was also considered, as the global recession resulted in sporadic closure of the capital markets in 2009 to companies of PDC’s size and credit rating.

On March 1, 2010, Mr. Amidon provided a proposed timeline for the acquisition process to Buchanan Ingersoll.

On March 23, 2010, Mr. Amidon provided copies of the formation documents for the 2004 partnerships to Buchanan Ingersoll.

On March 31, 2010, the special committee and PDC formally engaged Houlihan Lokey as the financial advisor to the special committee in connection with the acquisition of the 2004 partnerships by PDC.

On April 8, 2010, Mr. Amidon provided a draft of the form of proxy statement for the 2004 partnerships, including a form of merger agreement, to Buchanan Ingersoll. The initial draft of the merger agreement contemplated the merger of the partnership with and into the merger sub, with the merger sub surviving the merger, whereby, upon completion, investors would be entitled to receive a cash payment (which had not yet been determined) for each limited partnership unit they held. The initial draft of the merger agreement also included the following: (a) customary representations, warranties and covenants for each of PDC, the merger sub and the partnership; (b) conditions to completion of the merger, including (i) approval of the amendment to the partnership agreement and the merger agreement by the holders of at least a majority of the outstanding limited partnership units held by the investors, (ii) no event, circumstance, condition, development or occurrence causing, resulting in or having, or reasonably expected to cause, result in or have, a material adverse effect on the partnership’s business, operations, properties (in all cases taken as a whole), condition (financial or otherwise), results of operations, assets (in all cases taken as a whole), liabilities, cash flows or prospects or on market prices for oil and natural gas prevailing generally in the oil and gas industry shall have occurred (each an “Initial Draft MAE”), and (iii) other customary conditions; and (c) the ability of the parties to terminate the agreement in certain circumstances, including the ability of PDC to terminate the agreement if an Initial Draft MAE occurred. The initial draft did not provide the special committee, on behalf of such partnership, with the ability to terminate the agreement if such partnership were to receive a superior proposal to acquire all of such partnership’s limited partnership interests.

On April 14, 2010, the PDC board of directors held a meeting, from which the members of the special committee were absent, to consider a formal offer to acquire the 2004 partnerships. Members of PDC management and representatives of Andrews Kurth also attended the meeting. At the meeting, management provided the board with a presentation detailing the proposed offer to acquire the 2004 partnerships and discussed the reasons for making such an offer. Following discussion, the board approved the making of an offer to acquire the 2004 partnerships.

Later on April 14, 2010, the special committee held a meeting at which members of PDC management were present to provide an overview of PDC’s proposed offer to acquire the 2004 partnerships.

On April 28, 2010, the special committee held a meeting and reviewed and discussed the proposed acquisitions of the 2004 partnerships. The special committee, with the assistance of Houlihan Lokey and Buchanan Ingersoll, discussed potential counter-offers to PDC’s offers for the 2004 partnerships, and decided to present the counteroffers to PDC management subject to further review and discussions with Houlihan Lokey regarding certain valuation assumptions underlying PDC’s proposal.

Also on April 28, 2010, Buchanan Ingersoll provided the special committee’s comments to the form of merger agreement to PDC management and Andrews Kurth. Among other changes, the special committee requested (a) the removal of a proposed closing condition that there must not have been a material adverse effect on the applicable partnership’s prospects or on oil and natural gas prices, (b) the removal of proposed provisions which would have allowed PDC to terminate the merger agreement upon the occurrence of a material adverse effect with respect to the partnership or oil and natural gas prices and (c) the addition of a provision which would allow the applicable partnership to terminate the merger agreement if, prior to the approval of the merger by its limited partners, it were to receive a bona fide written offer to acquire, for cash, all of its limited partnership interests, which offer is not subject to a financing contingency, is otherwise on terms and conditions which the special committee determines in its good faith judgment (after consultation with its counsel and financial advisor) to be more favorable to the investors in such partnership than the merger and is reasonably capable of being completed.

On April 28, 2010, the special committee’s counteroffer was communicated to PDC management by Buchanan Ingersoll.

On May 3, 2010, the PDC board of directors held a meeting, from which the members of the special committee were absent, to consider the special committee’s counteroffer. Members of PDC management and representatives of Andrews Kurth also attended the meeting. At the meeting, management summarized for the board the terms of the special committee’s counteroffer, including its proposed revisions to the form of merger agreement. Following discussion, the board approved the merger of the 2004 partnerships with and into the merger sub, and the respective merger agreements, on the terms proposed by the special committee.

On May 6, 2010, Mr. Amidon provided a revised draft of the form of merger agreement to Buchanan Ingersoll. The revised draft reflected PDC’s acceptance of some, but not all, of the special committee’s proposed changes. PDC accepted all material changes to the merger agreement, including each of the changes described in clauses (a), (b) and (c) of the third preceding paragraph above.

On May 7, 2010, the merger sub was formed solely for the purpose of effecting the merger of PDC’s drilling partnerships.

On May 7, 2010, Andrews Kurth provided drafts of individualized merger agreements for the 2004 partnerships, including the agreed-upon price with respect to each such partnership, to Buchanan Ingersoll and Houlihan Lokey.

On May 25, 2010, the special committee held a meeting and reviewed and discussed the proposed transactions. Based on such review and discussions, the special committee approved the following terms for a revised counteroffer proposal for the 2004 partnerships on a per-unit basis: 2004-A — $8,400; 2004-B — $8,250; 2004-C — $5,650; and 2004-D — accepting PDC’s initial offer of $7,544 as stated. Later on May 25, 2010, the terms of the special committee’s revised proposal were communicated to PDC management by Buchanan Ingersoll.

On May 28, 2010, the PDC board of directors held a meeting, from which the members of the special committee were absent, to consider the special committee’s revised proposal. Members of PDC management and representatives of Andrews Kurth also attended the meeting. At the meeting, management summarized for the board the terms of the special committee’s revised proposal. Following discussion, the board approved the mergers of the 2004 partnerships with and into the merger sub, and the respective merger agreements, on the terms proposed by the special committee.

On June 1, 2010, Andrews Kurth provided revised drafts of individualized merger agreements for the 2004 partnerships, including the revised merger price with respect to each such partnership, to Buchanan Ingersoll and Houlihan Lokey for their review and discussion with the special committee.

On June 2, 2010, PDC, in its capacity as sole member of the merger sub, determined that the mergers of the 2004 partnerships with and into the merger sub were advisable and approved the respective merger agreements. The merger sub and the affiliated officers decided to pursue the mergers of the 2004 partnerships at this time based primarily on their analysis of the six factors listed in the bullet points above in connection with PDC’s determination to pursue the offers to repurchase the 2004 partnerships in March 2010.

On June 4, 2010, the special committee held a meeting to discuss the merger of the 2004 partnerships with the assistance of its legal and financial advisors. Following these discussions, the special committee approved the mergers of the 2004 partnerships and the merger agreements.

On June 7, 2010, PDC, the merger sub and the 2004 partnerships entered into the merger agreements. After the initial proxies for the four 2004 partnerships were filed with the SEC in early July 2010, PDC’s management began consideration of the timing and selection of additional partnership repurchase offers.

In August 2010, PDC’s management examined the potential economics for repurchasing the three 2005 partnerships, which were compliant in their SEC filings, as well as repurchasing the following partnerships that were not compliant with their SEC filings at that time, but were expected to become complaint in December 2010: the partnership, PDC 2003-A Limited Partnership, a West Virginia limited partnership (“2003-A”), PDC 2003-B Limited Partnership, a West Virginia limited partnership (“2003-B”), PDC 2003-C Limited Partnership, a West Virginia limited partnership (“2003-C”), and PDC 2003-D Limited Partnership, a West Virginia limited partnership (“2003-D,” and together with 2003-A, 2003-B and 2003-C (the “2003 partnerships”).

After deliberation on October 6, 2010, PDC’s management decided to pursue only the three 2005 partnerships at that time, primarily due to the delay that would be needed to wait for compliance of the other partnerships being considered for repurchase. In making its decision regarding the offer to repurchase the 2005 partnerships instead of other partnerships, PDC also considered the six factors listed in the bullet points above in connection with PDC’s determination to pursue the offers to repurchase the 2004 partnerships in March 2010.

On October 18, 2010, Buchanan Ingersoll contacted Houlihan Lokey, on behalf of the special committee, regarding Houlihan Lokey being re-engaged to act as the special committee’s financial advisor in connection the proposed transaction involving the three 2005 partnerships. On or about October 20, 2010, the special committee, with the assistance of Buchanan Ingersoll, discussed the terms of Houlihan Lokey’s proposed engagement, and comments were also sought from PDC management. On November 4, 2010, at the direction of the special committee, the Houlihan Lokey engagement letter dated as of November 1, 2010 was fully executed.

On November 2, 2010, PDC’s management provided a presentation to Buchanan Ingersoll, which was subsequently forwarded to the special committee, setting forth PDC’s proposed offer to acquire the 2005 partnerships, which was subject to the approval of the PDC board of directors, to the special committee and Buchanan Ingersoll. On November 2, 2010 PDC also provided a presentation to its board of directors regarding the proposed offers to repurchase the 2005 partnerships.

On November 4, 2010, the PDC board of directors held a telephonic meeting, from which the members of the special committee were absent, to consider a formal offer to acquire the 2005 partnerships. Members of PDC’s management and representatives of Andrews Kurth also attended the meeting. At the meeting, management provided the board with a presentation detailing the proposed offer to acquire the 2005 partnerships and discussed the reasons for making such an offer. Following discussion, the board approved the making of an offer to acquire the 2005 partnerships.

Later on November 4, 2010, the special committee held a telephonic meeting at which members of PDC’s management were initially present. Representatives of Houlihan Lokey and Buchanan Ingersoll also attended the meeting. At the meeting, the PDC management provided an overview of PDC’s proposed offer to acquire the 2005 partnerships. Based on such discussions, and subject to the finalization of the terms of the merger agreements, the special committee approved the following terms for revised counter-offer proposals for the 2005 partnerships on a per-unit basis: 2005-A — $7,000 per limited partnership unit; 2005-B — $5,506 per limited partnership unit; and RRPLP — $6,603 per limited partnership unit.

Later on November 4, 2010, Buchanan Ingersoll communicated to PDC’s management the special committee’s counteroffer.

On November 7, 2010, PDC’s board of directors held a telephonic meeting, from which the members of the special committee were absent, to consider the special committee’s counter-offers for the 2005 partnerships. All of the members of the board of directors were present other than the members of the special committee, who recused themselves, and Ms. Wakim, who was unable to attend due to illness. Members of PDC’s management and representatives of Andrews Kurth also attended the meeting. At the meeting, PDC’s management provided the board with a presentation detailing the counter-offers and their impact on PDC’s various acquisition metrics and potential rate of return. After extensive discussion, the members of the board present at the meeting who are not on the special committee approved the special committee’s counter-offers, as proposed.

On November 9, 2010 Mr. Amidon and representatives of Buchanan Ingersoll discussed the terms of the proposed merger agreements, and agreed to use the same terms negotiated by the parties in the repurchase offer for the 2004 partnerships earlier in 2010, including the following changes Buchanan Ingersoll and the special committee previously negotiated: (a) the removal of a proposed closing condition that there must not have been a material adverse effect on the applicable partnership’s prospects or on oil and natural gas prices, (b) the removal of proposed provisions which would have allowed PDC to terminate the merger agreement upon the occurrence of a material adverse effect with respect to such partnership or oil and natural gas prices and (c) the addition of a provision which would allow the applicable partnership to terminate the merger agreement if, prior to the approval of the merger by its limited partners, it were to receive a bona fide written offer to acquire, for cash, all of its limited partnership interests, which offer is not subject to a financing contingency, is otherwise on terms and conditions which the special committee determines in its good faith judgment (after consultation with its counsel and financial advisor) to be more favorable to the investors in such partnership than the merger and is reasonably capable of being completed. Mr. Amidon and representatives of Buchanan Ingersoll also agreed to revise the merger consideration offered under the merger agreements in accordance with the special committee’s request that the merger consideration be increased to include the sum of the amounts withheld from per unit cash distributions by such partnership from October 1, 2010 through February 28, 2011 for such partnership’s well refracturing plan.

On November 11, 2010, Andrews Kurth provided revised drafts of individualized merger agreements for each of the 2005 partnerships, including the merger price with respect to each such partnership, to Buchanan Ingersoll and Houlihan Lokey for their review.

On November 12, 2010, the special committee held a meeting to discuss the merger of the partnership and the other 2005 partnerships. Representatives of Houlihan Lokey and Buchanan Ingersoll also attended the meeting and participated in the special committee’s discussions regarding the proposed transactions. Following the discussion of the proposed mergers of the 2005 partnerships with the assistance of its legal and financial advisors, the special committee approved the mergers of the 2005 partnerships and the related merger agreements.

On November 16, 2010, PDC, the merger sub and the 2005 partnerships entered into the corresponding merger agreements.

On February 4, 2011, the 2005 partnerships filed their respective definitive proxy statement with the SEC. On or around February 7, 2011, the 2005 partnership mailed the definitive proxy statements to such partnership’s investors and began the process of soliciting votes with respect to the merger agreements and related mergers.

From February 8, 2011 through February 14, 2011, PDC’s management reviewed the current commodity prices, which had risen sharply versus the commodity prices used to determine the merger value offered to investors in connection with the merger agreement due to recent events in the Middle East, to determine if the amount of consideration offered to investors needed to be increased.

On February 18, 2011, PDC’s management determined that given the recent increases in commodity prices, it seemed appropriate to offer the investors additional cash consideration unit upon consummation of the merger, in addition to the consideration being offered to the investors in the merger agreements for each of the 2005 partnerships.

On February 21, 2011, PDC’s board of directors held a telephonic meeting, from which members of the special committee were absent, to consider offering investors additional cash consideration in light of increased commodity prices. After lengthy discussions and thorough review with PDC management, the board of directors of PDC approved offering the investors of the 2005 partnerships the following additional cash consideration, subject to approval of the merger agreement by the investors and consummation of the merger: 2005-A — $1,060 per limited partnership unit; 2005-B — $1,038 per limited partnership unit; RRPLP — $1,579 per limited partnership unit. The members of the PDC board of directors that voted in favor of offering investors additional cash consideration were Richard W. McCullough, Joseph E. Casabona, James M. Trimble and Kimberly Luff Wakim.

On February 28, 2011, Mr. Amidon distributed an initial draft of the proposal letter to Buchanan Ingersoll offering to provide to investors additional cash consideration upon consummation of the merger, in addition to the consideration being offered to the investors in the merger agreement.

On March 7, 2011, PDC discussed with Andrews Kurth that financial information for the 2005 partnerships had the possibility of becoming finalized prior to the date of the special meeting. As a result, PDC anticipated asking the investors to adjourn and delay the special meetings, in order to, among other things, permit PDC to provide investors with such 2005 partnership’s 2010 year-end financial statements and 2010 year-end reserve report.

On March 8, 2011, PDC provided investors of each of the 2005 partnerships with a letter (i) relating to the increased merger consideration PDC expected to offer to investors and (ii) informing investors that PDC expected to provide 2010 year-end financial statements and the 2010 reserve report for such 2005 partnership if the special meeting of such partnership was adjourned to a later date.

On March 25, 2011, investors approved the adjournment of the special meetings of the 2005 partnerships.

In late March 2011, PDC’s management examined the potential economics for repurchasing the four 2003 partnerships and 2002-D, which had each become current in its SEC filings, and determined to proceed with a proposal regarding the four 2003 partnerships and 2002-D. In making its decision regarding the offer to repurchase the 2003 partnerships and 2002-D instead of other partnerships that PDC serves as managing general partner, was based PDC’s analysis of the following factors:


	•	The more recent partnerships were still experiencing normal steep production declines and it was believed they could not be economically acquired in light of the limited partners’ 4.0X Put Right.

	•	Generally, the older the partnership, the better the economics for a refracturing, and also the more opportunity for faster production increases. PDC believes that well refracturing in the Codell formation of the Wattenberg Field wells, which may provide additional reserve development and production, optimally occurs five to ten years after the initial well completion. PDC has found that such refracturings generally increase the production rate and recoverable reserves for these wells. On average, the production resulting from PDC’s prior Codell well refracturings has achieved the modeled economics. The fact that the partnership’s wells will be nine years old in 2011 and therefore fall within the time frame that PDC believes is optimal to conduct well refracturings was one of the primary factors in PDC’s decision to repurchase the partnership at this time. However, the estimated value associated with the well refracturing was included in the calculation of the per unit merger value. Please see “Method of Determining Merger Value and Amount of Cash Offered — Components of Merger Value.”

	•	Under SEC rules, a merger proxy may only be filed by PDC if the partnership being considered for repurchase is current in its SEC financial reporting requirements. The 2003 partnerships and 2002-D were the oldest partnerships which were current in their SEC financial reporting requirements.

	•	Large derivative gains reflected in 2009 and the first five months of 2010 partnership distributions created a disincentive to PDC to increase the number of partnerships included in the offer, in light of the limited partners’ 4.0X Put Right, when compared to the potential PDC offer amounts which are determined primarily on future lower hedges and pricing.

	•	Potential alternative capital uses also influenced PDC’s decision regarding the number of partnerships proposed for merger. A higher rate of return may have been possible through alternative investments later in the year through potential future acquisitions or drilling opportunities.


	•	Capital availability was also considered, as the global recession resulted in sporadic closure of the capital markets in 2009 to companies of PDC’s size and credit rating.

On April 6, 2011, Buchanan Ingersoll contacted Houlihan Lokey, on behalf of the special committee, regarding Houlihan Lokey being re-engaged to act as the special committee’s financial advisor in connection with the proposed transaction involving the four 2003 partnerships and 2002-D.

On April 13, 2011, Mr. Amidon delivered to Buchanan Ingersoll an executed version of the letter dated February 28, 2011, confirming that PDC would offer to investors of the 2005 partnerships additional cash consideration upon consummation of the corresponding merger, in addition to the consideration being offered to the investors in the merger agreement.

Later on April 13, 2011, Mr. Amidon provided a preliminary presentation describing the pricing volatility adjustment mechanism to Buchanan Ingersoll. Mr. Amidon and representatives of Buchanan Ingersoll discussed the terms of the proposed merger agreements, and agreed to use the same terms negotiated by the parties in the repurchase offer for the 2004 partnerships and the 2005 partnerships, including the following changes Buchanan Ingersoll and the special committee previously negotiated: (a) the removal of a proposed closing condition that there must not have been a material adverse effect on the applicable partnership’s prospects or on oil and natural gas prices, (b) the removal of proposed provisions which would have allowed PDC to terminate the merger agreement upon the occurrence of a material adverse effect with respect to such partnership or oil and natural gas prices and (c) the addition of a provision which would allow the applicable partnership to terminate the merger agreement if, prior to the approval of the merger by its limited partners, it were to receive a bona fide written offer to acquire, for cash, all of its limited partnership interests, which offer is not subject to a financing contingency, is otherwise on terms and conditions which the special committee determines in its good faith judgment (after consultation with its counsel and financial advisor) to be more favorable to the investors in such partnership than the merger and is reasonably capable of being completed. Mr. Amidon and representatives of Buchanan Ingersoll also agreed to revise the merger agreements to include the pricing volatility adjustment mechanism that would provide increased merger consideration to investors in the event that certain commodity prices increased between the date of entering into the merger agreements and the date of mailing the proxy statements.

On April 15, 2011, the PDC board of directors held a telephonic meeting, from which the members of the special committee were not present and abstained from voting, to consider a formal offer to acquire the 2003 partnerships and 2002-D. Members of PDC’s management also attended the meeting. At the meeting, for the first time management discussed providing investors with additional consideration to address certain commodity price increases between the date of signing the merger agreements and the mailing date of the proxy statements (the “pricing volatility adjustment mechanism”). Management noted that between the date of entering into the merger agreements for each of the 2005 partnerships on November 16, 2010 and the date of filing the definitive proxy statements on February 4, 2011, due to events in the Middle East, commodity prices had risen sharply versus the commodity prices used to determine the merger value initially offered to investors. As a result, PDC had increased its offer to the investors of the 2005 partnerships to account for the increase in commodity prices between the date of entering into the merger agreements and the date of filing the definitive proxy statements. To account for potential increases in commodity prices between the date of the merger agreements and the date of filing the definitive proxy statements, management suggested offering the following additional merger consideration per limited partnership unit to investors of 2002-D and the 2003 partnerships: 2002-D — $275 2003-A — $580; 2003-B — $590; 2003-C — $510 and 2003-D — $410 for each increment of $5.00 per Bbl by which the arithmetic average of the five-year NYMEX futures price per Bbl for oil on the date immediately prior to filing the definitive proxy statements exceeds the arithmetic average of the five-year NYMEX futures price per Bbl for oil used to calculate the merger values in the merger agreements (assuming that the arithmetic average of the five-year NYMEX futures price per Mcf for gas has not decreased by an increment of $0.50 per Mcf or greater during the same period); and 2002-D — $200; 2003-A — $500; 2003-B — $525; 2003-C — $300 and 2003-D — $440 for each increment of $0.50 per Mcf by which the arithmetic average of the five-year NYMEX futures price per Mcf for gas on the date immediately prior to filing the definitive proxy statements exceeds the arithmetic average of the five-year NYMEX futures price per Mcf for gas used to calculate the merger values in the merger agreements (assuming that the arithmetic average of the five-year NYMEX futures price per Bbl for oil has not decreased by an increment of $5.00 per Bbl or greater during the same period). The partnerships were offered differing per unit adjustments due to each partnership’s having

different future cash flows and reserve estimates, oil to gas ratios, and hedged production and prices going forward. Management confirmed that the pricing volatility adjustment mechanism would provide increased merger consideration to investors in the event that certain commodity prices were to rise between the date of signing the merger agreements and the mailing date of the proxy statements, but could not decrease the original merger consideration offered to investors if commodity prices were to decrease during this same period. Management then provided the board with a presentation detailing the proposed offer to acquire the 2003 partnerships and 2002-D and discussed the reasons for making such an offer. Following discussion, the board approved the making of an offer with the pricing volatility adjustment mechanism, to acquire the 2003 partnerships and 2002-D.

On April 15, 2011, the special committee held a telephonic meeting and discussed the additional merger consideration offered from PDC to the investors of the 2005 partnerships. The meeting was attended by the special committee and the special committee’s counsel and financial advisors. Following the discussion of the proposed mergers of the 2005 partnerships, with the assistance of its legal and financial advisors, the special committee approved the mergers of the 2005 partnerships and the merger agreements, including the additional merger consideration offered by PDC.

Also at the special committee meeting held on April 15, 2011, the special committee discussed the mergers of the 2003 partnerships and 2002-D, at which members of PDC’s management were present. At the meeting, PDC’s management provided an overview of PDC’s proposed offer to acquire the 2003 partnerships and 2002-D.

On or about April 15, 2011, the special committee, with the assistance of Buchanan Ingersoll, discussed the terms of Houlihan Lokey’s proposed engagement, and comments were also sought from PDC management.

On April 20, 2011, at the direction of the special committee, the Houlihan Lokey engagement letter dated as of April 20, 2011 was fully executed.

On June 6, 2011, the special committee held a telephonic meeting with the assistance of its legal and financial advisors to discuss the mergers of the 2003 partnerships and 2002-D. The special committee decided to defer approval of the mergers until a later date and after the special committee and its advisors had the chance to review the actual merger agreement drafts which included the merger pricing volatility adjustment mechanism language. It was the consensus of the special committee that such language was an important component to the proposed transaction.

On June 7, 2011, Andrews Kurth provided revised drafts of the individualized merger agreements for each of the 2003 partnerships and 2002-D, including the merger price with respect to each such partnership and the pricing volatility adjustment mechanism, to Buchanan Ingersoll and Houlihan Lokey for their review.

On June 11, 2011, the special committee held a telephonic meeting with the assistance of its legal and financial advisors to discuss the mergers of the 2003 partnerships and 2002-D. Houlihan Lokey reviewed its financial analyses with respect to the partnership and the proposed merger and, at the request of the special committee, rendered Houlihan Lokey’s oral opinion to the special committee (which was subsequently confirmed in writing by delivery of Houlihan Lokey’s written opinion dated the same date) to the effect that, as of June 11, 2011, the consideration to be received by the unaffiliated holders of limited partnership interests in the proposed merger pursuant to the merger agreement was fair to such unaffiliated holders of limited partnership interests from a financial point of view. Buchanan Ingersoll also discussed with the special committee the terms of the proposed form of merger agreement, which was based on prior negotiations. Following the discussion of the proposed mergers of the 2003 partnerships and 2002-D with the assistance of its legal and financial advisors, the special committee approved the merger agreements and the following terms for the mergers of the 2003 partnerships and 2002-D on a per-unit basis: 2003-A — $8,125 per limited partnership unit; 2003-B — $7,864 per limited partnership unit; 2003-C — $5,603 per limited partnership unit; 2003-D — $5,795 per limited partnership unit; and 2002-D— $4,024 per limited partnership unit.

On June 20, 2011, PDC, in its capacity as sole member of the merger sub, determined that the mergers of the 2003 partnerships and 2002-D with and into the merger sub were advisable and approved the respective merger agreements. The merger sub and the affiliated officers decided to pursue the mergers of the 2003 partnerships and 2002-D at this time based primarily on their analysis of the six factors listed in the bullet points above in connection with PDC’s determination to pursue the offers to repurchase the 2003 partnerships and 2002-D in late March 2011.

On June 20, 2011, PDC, the merger sub and the 2003 partnerships and 2002-D entered into the corresponding merger agreements.

PDC’s Reasons for the Merger

PDC has elected to enter into the merger agreement for the following reasons:


	•	Shift in Corporate Strategy. Drilling partnerships are not part of PDC’s strategic plan going forward, and PDC wishes to buy them back, to the extent feasible. PDC has not established a drilling partnership since 2007 and has publicly announced a fundamental shift in its business strategy away from the partnership model to a more traditional exploration and production company model. In 2008, PDC eliminated from its strategic plan the use of sponsored drilling partnerships as a method of raising capital to fund development of PDC’s undeveloped properties due to availability of internally generated cash flow from operations and external borrowing capacity under its line of credit. PDC currently believes these other sources of financing are sufficient to meet its futures capital needs under its strategic plan. Due to the limited availability of properties and third-party drilling and completion services, PDC believes that this method of financing allows PDC to obtain 100% of the working interest in wells developed, while achieving a higher growth rate for both production and reserves and a better economic return to its shareholders. PDC anticipates that the merger will provide PDC with an immediate increase in its share of the partnership’s production and proved reserves since PDC will obtain from the investors the equity of the partnership not currently owned by PDC. PDC also wishes to position itself as a growth company. The merger will provide PDC with growth in both production and reserves from assets with which it is very familiar, and will permit PDC to invest further capital in those assets on a timetable of its own choosing.

	•	Enhanced Rate of Return. Assuming favorable future oil and gas prices, PDC believes that the merger could enhance the rate of return of the partnership’s assets, due to the potential realization of significant synergies relating to accelerating the pace of refracturing and recompleting the partnership’s wells, achieving scale efficiencies and optimizing revenue opportunities. PDC believes that the merger could accelerate the pace of refracturing the partnership’s wells, because PDC has immediate access to capital, which is not currently available to the partnership. PDC also anticipates the merger will result in greater operational flexibility. Currently, PDC owns approximately 27.9% of the partnership, yet has difficulty accessing the partnership’s reserves attributable to it. PDC believes that the partnership’s limited access to capital prevents the partnership from fully utilizing the reserves under its control. With greater current access to capital than the partnership, PDC believes that having the partnership’s assets under its direct control will enable PDC to realize operational benefits and cost synergies, including, among others, immediate access to the partnership’s reserves and undrilled locations and an opportunity to identify, pursue and accelerate the development of the partnership’s currently undrilled locations. PDC plans to continue producing the proved developed properties acquired from the investors. Additionally, pending a continued favorable economic environment and commodity price structure, PDC plans to initiate refracturing and recompleting work on the partnership’s Wattenberg Field wells as soon as possible in order to convert the proved undeveloped properties to proved developed resources.

	•	Administrative Efficiencies. Changes in the accounting rules and the regulation of public companies have significantly increased the third party and administrative costs of the partnership. Increasing costs reduce the funds available for distribution to investors. PDC anticipates that the consummation of the merger will eliminate costs, including time spent by PDC employees, related to preparing and filing the partnership’s SEC reports, financial statements and separate tax returns and responding to the concerns and inquiries of the investors. The merger will result in administrative efficiencies and cost reductions in the management and operation of the properties now owned by the partnership, particularly in the areas of audit, accounting and tax services, SEC reporting, engineering services, bookkeeping, data processing, record maintenance and communication with the partners. The value of the offer by PDC was calculated without reduction for these increased levels of accounting and reporting expenses.

The Partnership’s Reasons for the Merger

The special committee has elected to cause the partnership to enter into the merger agreement and to present the proposed merger transaction to the investors for their consideration for the following reasons:


	•	Declining Natural Gas Prices and Per Unit Distributions. Future natural gas prices are uncertain because low-cost shale plays, particularly the Marcellus shale, may set national prices going forward. These low-cost shale plays, which have experienced a large increase in development in recent years, have added significant proved reserves and increased production primarily in the eastern portion of the United States where demand is the highest. These reserves now represent a much larger part of overall natural gas reserves and production in the United States and have the potential to affect the variability of open market pricing more significantly than in the past, along with a potential oversupply situation in a downturned economy. As a result of lower natural gas prices, the high natural gas hedging prices which PDC has achieved for the partnership during the last several years are not available at this time for future periods. PDC expects that lower realized natural gas prices, declining production and any withholdings for the additional Codell formation development plan will result in reduced per unit distributions in the future.

	•	Difficulty with Financing Refracturing Operations. Fully developing all of the partnership’s properties, including through refracturing and recompletion operations, would require substantial capital expenditures. Because of the restrictions set forth in the partnership agreement on borrowing money and making assessments on limited partnership units, the partnership would be unable to fund such capital expenditures without retaining all or a substantial portion of the partnership’s cash flow. This would reduce or eliminate partnership distributions to investors while the work is being conducted and paid for, and could create phantom income (reportable income for tax purposes without a corresponding cash distribution) for investors with respect to the cash used to fund the capital expenditures, although tax deductions might offset a portion of such phantom income.

	•	Liquidity. The merger provides liquidity to the investors at a price based on historical cash flows, not on limited market demand for illiquid partnership interests. Each investor will receive a cash payment in exchange for such investor’s limited partnership units shortly after completion of the merger. None of the limited partnership units are traded on a national stock exchange or in any other significant market. No liquid market exists for limited partnership units. Although some limited partnership units are occasionally sold in private or over-the-counter transactions, we believe the potential buyers in such transactions are few and the prices generally reflect a significant discount for illiquidity.

	•	Elimination of Partnership Tax Reports. The merger will eliminate the investors’ Schedule K-1 tax reports in the partnership for tax years after the merger occurs. This is expected to simplify the investors’ individual tax return preparation and reduce preparation costs.

Position of the Partnership Affiliates as to the Fairness of the Merger to the Unaffiliated Holders of Limited Partnership Interests

The rules of the SEC require each of the partnership affiliates to express their belief as to the substantive and procedural fairness of the merger to the unaffiliated holders of limited partnership interests. The views of the partnership affiliates with respect to the fairness of the merger to the unaffiliated holders of limited partnership interests are not, and should not be construed as, a recommendation to any unaffiliated holder of limited partnership interests as to how that unaffiliated holder of limited partnership interests should vote on the proposal to adopt the merger agreement.

In considering the belief of the partnership affiliates with respect to the merger, the unaffiliated holders of limited partnership interests should be aware that partnership affiliates have interests in the merger that are different from, or in addition to, the interests of the unaffiliated holders of limited partnership interests generally. PDC, as managing general partner of the partnership, has a duty to manage the partnership in the best interests of the limited partners of the partnership. However, PDC also has a duty to operate its business for the benefit of its shareholders. Consequently, PDC’s duties to its shareholders may conflict with its duties to the unaffiliated holders of limited partnership interests.

In addition, the members of the board of directors of PDC have a duty to cause PDC to manage the partnership in the best interests of the limited partners of the partnership. However, members of the board of directors of PDC also have a duty to operate PDC’s business for the benefit of its shareholders, and board members who are also officers of PDC have a duty to operate PDC’s business in PDC’s best interests. Consequently, the duties of the members of the board of directors of PDC to the investors may conflict with the duties of those members to PDC and PDC’s shareholders. See “Special Factors with Respect to the Merger — Conflicting Duties of PDC, Individually and as the General Partner” beginning on page 42.

None of the partnership affiliates participated in the deliberation processes of the special committee, or in the conclusions of the special committee, with respect to the substantive and procedural fairness of the merger to the investors, nor did they undertake any independent evaluation of the fairness of the merger or engage a financial advisor for such purpose. Nevertheless, each of the partnership affiliates believes that the proposed merger is fair to the unaffiliated holders of limited partnership interests on the basis of the following factors:


	•	the special committee, which is comprised of four directors of PDC who are not officers or employees of the partnership or PDC and have no direct economic interest in the partnership, negotiated the merger agreement and the transactions contemplated thereby on behalf of the partnership and has approved the merger agreement, has determined that the merger is advisable and in the best interests of the partnership and reasonably believes that the merger is fair to the unaffiliated holders of limited partnership interests;

	•	the special committee was advised by outside legal counsel and an independent financial advisor in relation to the merger;

	•	notwithstanding the fact that the partnership affiliates are not entitled to rely on and did not rely on such opinion, the special committee requested and received from Houlihan Lokey an opinion, addressed to the special committee with respect to whether, that, as of June 11, 2011, the consideration to be received by the unaffiliated holders of limited partnership interests in the proposed merger pursuant to the merger agreement was fair to such unaffiliated holders of limited partnership interests from a financial point of view;

	•	there is no current established public trading market for the units. Trading in the limited partnership units occurs in a highly illiquid, thinly-traded market, is sporadic and occurs solely through private transactions. If the merger is not consummated, holders may have no other ability to liquidate their investment in the partnership. The merger will provide liquidity for unaffiliated holders of limited partnership interests whose ability to sell their units is adversely affected by the limited trading volume.

	•	the merger consideration is all cash, allowing the unaffiliated holders of limited partnership interests to immediately realize a certain value for all their limited partnership units in the partnership;

	•	the merger agreement is not subject to a financing contingency and there are relatively few closing conditions to the merger, which limits the execution risk associated with the completion of the merger, and thus makes it more likely the merger will be consummated promptly if the unaffiliated holders of limited partnership interests approve the merger;

	•	the partnership is not required to pay PDC or its affiliates a termination or “break up” fee if the special committee, on behalf of the partnership, terminates the merger agreement to enter into an acquisition agreement with respect to a superior proposal.

	•	other than the current proposal, the partnership has not received any acquisition proposals;

	•	the merger is conditioned upon holders of a majority of the outstanding limited partnership units held by the unaffiliated holders of limited partnership interests voting to approve both the amendment to the partnership agreement and the merger agreement; and

	•	unaffiliated holders of limited partnership interests who do not vote in favor of the merger agreement and who comply with certain procedural requirements will be entitled, upon completion of the merger, to exercise statutory appraisal rights under West Virginia law.

Each of the partnership affiliates believe the merger is procedurally fair to unaffiliated holders of limited partnership interests, based on the following factors:


	•	the special committee, which negotiated the merger agreement and the transactions contemplated thereby on behalf of the partnership, is comprised of four directors of PDC who are not officers or employees of the partnership or PDC and have no direct economic interest in the partnership. The special committee retained their own outside legal counsel and financial advisor. The special committee also met regularly, without the participation of the partnership affiliates, to discuss the partnership’s strategic alternatives and the terms of the merger transaction;

	•	under certain circumstances, the special committee, on behalf of the partnership, has the ability to terminate the merger agreement to enter into an acquisition agreement with respect to a superior proposal, and the partnership is not required to pay any of the partnership affiliates a termination or “break up” fee; and

	•	approval of each of the amendments to the partnership agreement and the merger agreement requires the affirmative vote of the holders of a majority of the outstanding limited partnership units held by unaffiliated holders of limited partnership interests, and limited partnership units owned by PDC or its affiliates will not be considered as outstanding limited partnership units for the purposes of each proposal and may not be voted.

The partnership affiliates also considered the following countervailing factors:


	•	if the merger transaction is consummated, the unaffiliated holders of limited partnership interests will cease to participate in the future earnings or growth of the partnership or benefit from increases, if any, in the value of the partnership following completion of the merger;

	•	the possible disruption to PDC’s business that may result from the announcement of the transaction and the resulting potential distraction of the attention of PDC’s management;


	•	the interests of the partnership affiliates in the merger that are different from, or in addition to, the interests of the unaffiliated holders of limited partnership interests generally. PDC’s duties to its shareholders may conflict with its duties to the unaffiliated holders of limited partnership interests (see the discussion above and “Special Factors with Respect to the Merger — Conflicting Duties of PDC, Individually and as the General Partner” beginning on page 42);


	•	the risk that the conditions to the completion of the merger may not be satisfied and therefore the merger may not be completed;


	•	the complex nature of the West Virginia statutory scheme for appraisal rights. Failure to follow the statutory provisions precisely may result in the loss of investor’s appraisal rights under West Virginia law (see “Rights of Dissenting Investors” beginning on page 62 and the West Virginia statutory provisions relating to appraisal rights which are included in their entirety as Appendix C to this proxy statement); and


	•	the receipt of the cash consideration by investors pursuant to the merger will be a taxable transaction to the investors (see “Material U.S. Federal Income Tax Consequences” beginning on page 44).

The foregoing discussion of factors considered by each of the partnership affiliates is not intended to be exhaustive, but includes the material factors considered by the partnership affiliates. The partnership affiliates did not find it practicable to assign, nor did any of them assign, relative weights to the individual factors considered in reaching their conclusions as to fairness to the unaffiliated holders of limited partnership interests. Each of the partnership affiliates may have weighed these factors differently.

In reaching their conclusion as to fairness, the partnership affiliates did not consider historical prices for the limited partnership units held by the unaffiliated holders of limited partnership interests, including previous purchases by PDC, because such prices were supported by different markets and industry conditions than those presently existing. The partnership’s limited partnership units are not traded on a national stock exchange or in any other significant market. The partnership affiliates believe any market for the partnership interests is highly illiquid and that sporadic trading prices of partnership units reflect an illiquidity discount, and consequently are not reliable as indicators of fair value. In addition, future natural gas prices are uncertain because recent low-cost shale plays, particularly in the Marcellus shale, may set national prices going forward. These low-cost shale plays, which have experienced a large increase in development in recent years, have added significant proved reserves and increased production primarily in the eastern portion of the United States where demand is the highest. These reserves now

represent a much larger part of overall natural gas reserves and production in the United States and have the potential to affect the variability of open market pricing more significantly than in the past, along with a potential oversupply situation in a downturned economy.

As a result, currently the partnership’s production is hedged at a significantly lower price compared to previous periods. Historical purchases by PDC reflected the value of higher natural gas hedging prices that PDC had previously achieved for the partnership, but which are not currently available for the partnership for future periods. Consequently, the partnership affiliates did not consider historical prices for the limited partnership units held by unaffiliated holders of limited partnership interests.

The partnership affiliates did not consider the partnership’s net book value, per-merger going concern value, or liquidation value in their evaluation of the fairness of the merger to the unaffiliated holders of limited partnership interests of the partnership because they did not believe that the partnership’s net book value, pre-merger going concern value or liquidation value were material or relevant to a determination of the substantive fairness of the merger. The partnership affiliates did not believe that the net book value of the partnership was material to their conclusion regarding the fairness of the merger because, in their view, net book value is not indicative of the partnership’s value as a going concern since it is a purely historical measurement of financial position in accordance with U.S. generally accepted accounting principles and is not forward-looking, but rather is indicative of historical costs.

The partnership affiliates did not establish a pre-merger going concern value for the partnership’s equity for the purpose of determining the fairness of the merger because the partnership affiliates do not believe there is a single method of determining going concern value and, therefore, did not base their valuation of the partnership on a concept that is subject to various interpretations. In contrast, the partnership affiliates believe the merger is fair to unaffiliated holders of limited partnership interests because PDC’s method of determining the merger value and the amount of cash offered to unaffiliated holders of limited partnership interests was based on a more established industry method for valuing net assets. See “Method of Determining Merger Value and Amount of Cash Offered” beginning of page 56.

The partnership affiliates did not consider the liquidation value of the partnership, because they consider the partnership to be a viable going concern and have no plans to liquidate the partnership. The liquidation of the partnership was not considered to be a viable course of action based on the partnership affiliate’s desire for the partnership to continue to conduct its business and remain an integral component of PDC’s overall strategy regardless of whether the merger is consummated.

The partnership affiliates are not aware of any offer made during the last two years to acquire the partnership, and as a result no comparison to any such offer could be made, and no such offers were considered by any of the partnership affiliates in reaching their conclusions as to fairness. The merger sub did not consider the potential for alternative transactions involving the partnership because the merger sub did not intend to consider or participate in any alternative transaction involving the partnership. As a result, the merger sub did not evaluate the prices potentially attainable in an alternative transaction.

The Partnership’s Discussion of the Fairness of the Merger; Recommendation of the Special Committee on Behalf of the Partnership


	•	the form and amount of consideration offered to the partners;

	•	the comparison of the cash payments in the merger to the diminished future cash distributions otherwise expected as oil and gas production continues to decline;

	•	the increasing complexity of and cost of complying with accounting rules and regulations and SEC reporting obligations;

	•	expectations regarding future commodity prices; and

	•	the elimination after the merger of investors’ tax preparation costs relating to partnership tax information.

The special committee also considered certain procedural aspects of the proposed merger transaction in the course of evaluating the fairness to the unaffiliated investors. At the insistence of the special committee, the proposed merger is structured so that approval of a majority of unaffiliated investors is required in order to consummate the transaction. Moreover, the board of directors of PDC formed the special committee for the purpose of acting on behalf of the unaffiliated investors in negotiating the terms of the proposed merger transaction. The special committee consists solely of independent directors of PDC, none of whom are employees of PDC or its affiliates. In connection with the transaction, the special committee also engaged its own legal counsel, Buchanan Ingersoll, and its own financial advisor, Houlihan Lokey, to provide advice to the special committee independent of PDC and its advisors. The special committee met several times with Buchanan Ingersoll and Houlihan Lokey, independent of the PDC board of directors, to review and with the assistance of these advisors, evaluated and, based on its evaluation, approved the proposed merger transaction.

In addition, in the course of reaching its decision regarding the proposed merger transaction, the special committee considered the financial analysis reviewed and discussed with the special committee by representatives of Houlihan Lokey, as well as the oral opinion of Houlihan Lokey to the special committee on June 11, 2011 (which was subsequently confirmed in writing by delivery of Houlihan Lokey’s written opinion dated the same date) with respect to the fairness to the unaffiliated holders of limited partnership interests from a financial point of view of the consideration to be received by the unaffiliated holders of limited partnership interests in the proposed merger pursuant to the merger agreement. In evaluating the substantive fairness of the proposed merger transaction, the special committee considered the implied valuation reference ranges indicated by Houlihan Lokey’s selected companies, selected transactions and discounted cash flow analyses. The special committee noted that the merger consideration was generally above or within the implied valuation reference ranges indicated by those analyses. While the results of each analysis were taken into account in reaching its overall conclusion with respect to fairness, the special committee did not make separate or quantifiable judgments regarding Houlihan Lokey’s individual valuation analyses but viewed the analyses, taken together, as supportive of its conclusion that the merger was fair to the unaffiliated holders of limited partnership interests. The special committee did not view the implied valuation reference range indicated by any analyses as a controlling factor in its evaluation of the substantive fairness of the merger because, among other things, the implied valuation reference ranges indicated by Houlihan Lokey’s analyses were illustrative and not necessarily indicative of actual values or predictive of future results or values, which may be significantly more or less favorable than those suggested by the analyses. In addition, Houlihan Lokey’s analyses did not purport to be appraisals or to reflect the prices at which businesses or securities actually may be sold, which may depend on a variety of factors, many of which are beyond the partnership’s control and the control of Houlihan Lokey. The special committee also recognized that while such analyses were informative and useful, much of the information used in, and accordingly the results of, Houlihan Lokey’s analyses were inherently subject to substantial uncertainty.

In reaching its conclusion as to fairness, the special committee did not consider historical or current prices for the limited partnership units held by the unaffiliated holders of limited partnership interests, including previous purchases by PDC, because the special committee believed that those transactions were not regular in their frequency and occurred in an illiquid and limited market. Since the partnership’s public offering in 2002, PDC has repurchased 143.1 units of the partnership from investors at an average price per limited partnership unit of $5,360. For the fiscal year ended December 31, 2010 and the six months ended June 30, 2011, PDC repurchased 2.0 units and 4.75 units, respectively, from investors at an average repurchase price per limited partnership unit of $2,045 and $1,265, respectively. The decline in repurchase price paid by PDC in the last fifteen months compared to historical averages was primarily due to lower realized natural gas prices and declining production by the partnership. The special committee, in part, based its evaluation of historical and current limited partnership unit prices on the fact that the partnership’s limited partnership units are not traded on a national stock exchange or in any other significant market. Additionally, purchases made by PDC generally would have occurred pursuant to the 4.0X Put Right and determined under different financial conditions which had limited relevance to the proposed transaction. Moreover, because of various market events and market uncertainty, the partnership’s production is currently hedged at a significantly lower price compared to previous periods. As a result, historical purchases by PDC reflected the value of higher natural gas hedging prices that PDC had previously achieved for the partnership, but which are not currently available for the partnership for future periods. Therefore, PDC repurchases did not provide comparable information that was useful to the special committee.

The special committee did not consider the partnership’s net book value, pre-merger going concern value, or liquidation value in evaluating the fairness of the merger to the unaffiliated holders of limited partnership interests

because the special committee believed that the implied valuation reference ranges for indicated selected companies, selected transactions and discounted cash flow analyses that it did consider were the most relevant metrics for its consideration and therefore focused its attention on those factors. As such, the special committee did not believe that the partnership’s net book value, pre-merger going concern value or liquidation value were material or relevant to a determination of the substantive fairness of the merger.

More specifically, the special committee did not believe that the net book value of the partnership was material to its conclusion regarding the fairness of the merger because the special committee believed that net book value is indicative of historical financial position but is not necessarily a useful indicator of the current or future value. The special committee also did not establish a pre-merger going concern value for the partnership’s equity for the purpose of determining the fairness of the merger because it believed that a going concern value was not an indicative measure of value as compared to those factors noted above that the special committee did consider. In reaching its conclusion as to fairness, the special committee also did not consider the liquidation value of the partnership because it considers the partnership to be a viable going concern and that, as the special committee understood it, the liquidation of the partnership was not considered to be a viable course of action based on PDC’s desire for the partnership to continue to conduct its business and remain an integral component of PDC’s overall strategy regardless of whether the merger is consummated.

In addition, the special committee did not consider offers made by unaffiliated persons during the last two years, as no such offers were made to PDC, the affiliated officers, the partnership or the special committee. See “Special Factors with Respect to the Merger — Third-Party Offers.”

For these reasons, the special committee encourages you to vote FOR the proposals to approve the amendment and the merger agreement and FOR any proposal to adjourn or postpone the special meeting to a later date, including an adjournment or postponement to solicit additional proxies if, at the special meeting, the number of limited partnership units present or represented by proxy and voting in favor of the approval of the merger agreement or the amendment to the partnership agreement is insufficient to approve the merger agreement or the amendment of the partnership agreement, respectively.

In view of the numerous factors taken into consideration, the special committee did not consider it practical to, and did not attempt to, quantify or assign relative weights to the factors considered by it in reaching its decision. The special committee also considered the likelihood, benefits and costs of other transactions, including third-party offers. The special committee will consider any offers from third parties to purchase the partnership or its assets. See “Third-Party Offers” for a description of the procedures for these offers.

Opinion of the Special Committee’s Financial Advisor

On June 11, 2011, Houlihan Lokey rendered its oral opinion to the special committee (which was subsequently confirmed in writing by delivery of Houlihan Lokey’s written opinion dated the same date) to the effect that, as of June 11, 2011, the consideration to be received by the unaffiliated holders of limited partnership interests in the proposed merger pursuant to the merger agreement was fair to such unaffiliated holders of limited partnership interests from a financial point of view. For purposes of its opinion, Houlihan Lokey defined the unaffiliated holders of limited partnership interests as the holders of limited partnership interests in PDC 2002-D Limited Partnership (the “Limited Partnership”) other than PDC and its affiliates.

Houlihan Lokey’s opinion was directed to the Special Committee and only addressed the fairness, from a financial point of view, to the unaffiliated holders of limited partnership interests of the consideration to be received by the unaffiliated holders of limited partnership interests in the proposed merger pursuant to the merger agreement, and did not address any other aspect or implication of the proposed merger. The summary of Houlihan Lokey’s opinion in this proxy statement is qualified in its entirety by reference to the full text of its written opinion, which is included as Appendix B to this proxy statement and sets forth the procedures followed, assumptions made, qualifications and limitations on the review undertaken and other matters considered by Houlihan Lokey in preparing its opinion. However, neither Houlihan Lokey’s written opinion nor the summary of its opinion and the related analyses set forth in this proxy statement are intended to be, and they do not constitute, advice or a recommendation to any holder of limited partnership interests as to how such limited partner should act or vote with respect to any matter relating to the merger.

In arriving at its opinion, Houlihan Lokey:


	•	reviewed a draft of the merger agreement received by Houlihan Lokey on June 7, 2011;

	•	reviewed certain publicly available business and financial information relating to the Limited Partnership that Houlihan Lokey deemed to be relevant;

	•	reviewed certain information relating to the historical, current and future operations, financial condition and prospects of the Limited Partnership made available to Houlihan Lokey by PDC, including, (a) financial projections provided to Houlihan Lokey by the management of PDC relating to the Limited Partnership for the remaining life of the Limited Partnership’s wells and (b) certain oil and gas reserve reports prepared by PDC’s independent oil and gas reserve engineers (the “Reserve Reports”) containing estimates with respect to the Limited Partnership’s oil and gas reserves;

	•	spoke with certain members of the management of PDC and members of the special committee and certain of their representatives and advisors regarding the business, operations, financial condition and prospects of the Limited Partnership, the proposed merger and related matters;

	•	compared the financial and operating performance of the Limited Partnership with that of other public companies that Houlihan Lokey deemed to be relevant;

	•	considered the publicly available financial terms of certain transactions that Houlihan Lokey deemed to be relevant;

	•	reviewed a certificate addressed to Houlihan Lokey from senior management of PDC which contained, among other things, representations regarding the accuracy of the information, data and other materials (financial or otherwise) provided to, or discussed with, Houlihan Lokey by or on behalf of PDC and the Limited Partnership; and

	•	conducted such other financial studies, analyses and inquiries and considered such other information and factors as Houlihan Lokey deemed appropriate, including, without limitation, certain alternative oil and gas commodity pricing assumptions and probabilities.

Houlihan Lokey relied upon and assumed, without independent verification, the accuracy and completeness of all data, material and other information furnished, or otherwise made available, to it, discussed with or reviewed by it, or publicly available, and did not assume any responsibility with respect to such data, material and other information. In addition, management of PDC advised Houlihan Lokey, and Houlihan Lokey assumed, that the financial projections that it reviewed reflect the best currently available estimates and judgments of PDC’s management as to the future financial results and condition of the Limited Partnership and Houlihan Lokey expressed no opinion with respect to such projections or the assumptions on which they were based. With respect to the oil and gas reserve estimates for the Limited Partnership set forth in the Reserve Reports that Houlihan Lokey reviewed, the management of PDC advised Houlihan Lokey, and Houlihan Lokey assumed, that such estimates were reasonably prepared on bases reflecting the best currently available estimates and judgments of PDC and its independent oil and gas reserve engineers with respect to the oil and gas reserves of the Limited Partnership. With respect to the alternative oil and gas commodity pricing assumptions and probabilities that Houlihan Lokey utilized for purposes of its analyses, Houlihan Lokey was advised by the management of PDC, and Houlihan Lokey assumed, that such assumptions were a reasonable basis on which to evaluate the future financial performance of the Limited Partnership and were appropriate for such purposes. Houlihan Lokey relied upon and assumed, without independent verification, that there had been no change in the business, assets, liabilities, financial condition, results of operations, cash flows or prospects of the Limited Partnership since the date of the most recent financial statements provided to it that would be material to its analyses or its opinion, and that there was no information or any facts that would make any of the information reviewed by Houlihan Lokey incomplete or misleading.

Houlihan Lokey relied upon and assumed, without independent verification, that (a) the representations and warranties of all parties to the merger agreement and all other related documents and instruments that are referred to therein were true and correct, (b) each party to the merger agreement and such other related documents and instruments would fully and timely perform all of the covenants and agreements required to be performed by such party, (c) all conditions to the consummation of the proposed merger would be satisfied without waiver thereof, and

(d) the proposed merger would be consummated in a timely manner in accordance with the terms described in the merger agreement and such other related documents and instruments, without any amendments or modifications thereto. Houlihan Lokey also relied upon and assumed, without independent verification, that (i) the proposed merger would be consummated in a manner that complies in all respects with all applicable federal and state statutes, rules and regulations, and (ii) all governmental, regulatory, and other consents and approvals necessary for the consummation of the proposed merger would be obtained and that no delay, limitations, restrictions or conditions would be imposed or amendments, modifications or waivers made that would have an effect on the Limited Partnership that would be material to its analyses or its opinion. At the direction of the special committee, the opinion did not address in any respect adjustments to the consideration pursuant to the merger agreement or otherwise subsequent to the date the opinion. In addition, Houlihan Lokey relied upon and assumed, without independent verification, that the final form of the merger agreement would not differ in any respect from the draft of the merger agreement identified above.

Furthermore, in connection with its opinion, Houlihan Lokey was not requested to make, and did not make, any physical inspection or independent appraisal or evaluation of any of the assets, properties or liabilities (fixed, contingent, derivative, off-balance-sheet or otherwise) of the Limited Partnership or any other party, nor was Houlihan Lokey provided with any such appraisal or evaluation, other than the Reserve Reports. Houlihan Lokey did not estimate, and expressed no opinion regarding, the liquidation value of any entity or business. Houlihan Lokey did not undertake any independent analysis of any potential or actual litigation, regulatory action, possible unasserted claims or other contingent liabilities, to which PDC was or may be a party or was or may be subject, or of any governmental investigation of any possible unasserted claims or other contingent liabilities to which the Limited Partnership was or may be a party or was or may be subject. Houlihan Lokey is not an expert in the evaluation of oil and gas reserves and Houlihan Lokey expressed no view as to the reserve quantities, or the development or production (including, without limitation, as to the feasibility or timing thereof), of any oil and gas properties of the Limited Partnership.

Houlihan Lokey was not requested to, and did not, (a) initiate or participate in any discussions or negotiations with, or solicit any indications of interest from, third parties with respect to the proposed merger, the securities, assets, businesses or operations of the Limited Partnership or any other party, or any alternatives to the proposed merger, (b) negotiate the terms of the proposed merger, or (c) advise the special committee, the board of directors of PDC or any other party with respect to alternatives to the proposed merger. Houlihan Lokey’s opinion was necessarily based on financial, economic, market and other conditions as in effect on, and the information made available to it as of, the date of its opinion. As PDC and the Limited Partnership were aware, the financial projections and estimates that Houlihan Lokey reviewed relating to the future financial performance of the Limited Partnership reflect certain assumptions regarding the oil and gas industry which are subject to significant volatility and which, if different than assumed, could have a material impact on Houlihan Lokey’s analyses and opinion. Except as otherwise provided in its engagement letter, Houlihan Lokey did not undertake, and is under no obligation, to update, revise, reaffirm or withdraw its opinion, or otherwise comment on or consider events occurring or coming to our attention after the date of its opinion.

Houlihan Lokey’s opinion was furnished for the use and benefit of the special committee (solely in its capacity as such) in connection with its consideration of the proposed merger and may not be used for any other purpose without Houlihan Lokey’s prior written consent. Houlihan Lokey’s opinion should not be construed as creating any fiduciary duty on Houlihan Lokey’s part to any party. Houlihan Lokey’s opinion is not intended to be, and does not constitute, a recommendation to the special committee, the Board of Directors of PDC, any security holder of the Limited Partnership or any other person as to how to act or vote with respect to any matter relating to the proposed merger. Houlihan Lokey has consented to the inclusion of a copy of its opinion as Appendix B to this proxy statement.

Houlihan Lokey’s opinion only addressed the fairness to the unaffiliated holders of limited partnership interests from a financial point of view of the consideration to be received by the unaffiliated holders of limited partnership interests in the proposed merger pursuant to the merger agreement and did not address any other aspect or implication of the proposed merger or any agreement, arrangement or understanding entered in connection therewith or otherwise. In addition, Houlihan Lokey’s opinion did not express an opinion as to or otherwise address, among other things: (i) the underlying business decision of the special committee, the Board of Directors of PDC,

PDC, the Limited Partnership, their respective security holders or any other party to proceed with or effect the proposed merger, (ii) the terms of any arrangements, understandings, agreements or documents related to, or the form, structure or any other portion or aspect of, the proposed merger or otherwise (other than the consideration to the extent expressly specified herein), (iii) the fairness of any portion or aspect of the proposed merger to the holders of any class of securities, creditors or other constituencies of the Limited Partnership or PDC, or to any other party, except as expressly set forth in the last sentence of its opinion, (iv) the relative merits of the proposed merger as compared to any alternative business strategies that might exist for the Limited Partnership, PDC or any other party or the effect of any other transaction in which the Limited Partnership, PDC or any other party might engage, (v) the fairness of any portion or aspect of the proposed merger to any one class or group of the Limited Partnership’s or any other party’s security holders vis-à-vis any other class or group of the Limited Partnership’s or such other party’s security holders (including, without limitation, the allocation of any consideration amongst or within such classes or groups of security holders), (vi) whether or not the Limited Partnership, PDC, their respective security holders or any other party is receiving or paying reasonably equivalent value in the proposed merger, (vii) the solvency, creditworthiness or fair value of the Limited Partnership or any other participant in the proposed merger, or any of their respective assets, under any applicable laws relating to bankruptcy, insolvency, fraudulent conveyance or similar matters, or (viii) the fairness, financial or otherwise, of the amount, nature or any other aspect of any compensation to or consideration payable to or received by any officers, directors or employees of any party to the proposed merger, any class of such persons or any other party, relative to the consideration or otherwise. Furthermore, no opinion, counsel or interpretation was intended in matters that require legal, regulatory, accounting, insurance, tax or other similar professional advice. It was assumed that such opinions, counsel or interpretations have been or will be obtained from the appropriate professional sources. Furthermore, Houlihan Lokey relied, with the special committee’s consent, on the assessments by the special committee, the Board of Directors of PDC, PDC and their respective advisors, as to all legal, regulatory, accounting, insurance and tax matters with respect to the Limited Partnership and the proposed merger. The issuance of Houlihan Lokey’s opinion was approved by a committee authorized to approve opinions of such nature.

In preparing its opinion to the special committee, Houlihan Lokey performed a variety of analyses, including those described below. The summary of Houlihan Lokey’s valuation analyses described below is not a complete description of the analyses underlying Houlihan Lokey’s fairness opinion. The preparation of a fairness opinion is a complex process involving various quantitative and qualitative judgments and determinations with respect to the financial, comparative and other analytic methods employed and the adaptation and application of those methods to the unique facts and circumstances presented. As a consequence, neither Houlihan Lokey’s opinion nor the analyses underlying its opinion are readily susceptible to partial analysis or summary description. Houlihan Lokey arrived at its opinion based on the results of all analyses undertaken by it and assessed as a whole and did not draw, in isolation, conclusions from or with regard to any individual analysis, analytic method or factor. Accordingly, Houlihan Lokey believes that its analyses must be considered as a whole and that selecting portions of its analyses, analytic methods and factors, without considering all analyses and factors or the narrative description of the analyses, could create a misleading or incomplete view of the processes underlying its analyses and opinion.

In performing its analyses, Houlihan Lokey considered business, economic, industry and market conditions, financial and otherwise, and other matters as they existed on, and could be evaluated as of, the date of the written opinion. No company, transaction or business used in Houlihan Lokey’s analyses for comparative purposes is identical to the Limited Partnership or the proposed merger. While the results of each analysis were taken into account in reaching its overall conclusion with respect to fairness, Houlihan Lokey did not make separate or quantifiable judgments regarding individual analyses. The implied valuation reference ranges indicated by Houlihan Lokey’s analyses are illustrative and not necessarily indicative of actual values or predictive of future results or values, which may be significantly more or less favorable than those suggested by the analyses. In addition, any analyses relating to the value of assets, businesses or securities do not purport to be appraisals or to reflect the prices at which businesses or securities actually may be sold, which may depend on a variety of factors, many of which are beyond our control and the control of Houlihan Lokey. Much of the information used in, and accordingly the results of, Houlihan Lokey’s analyses are inherently subject to substantial uncertainty.

Houlihan Lokey’s opinion and analyses were provided to the special committee in connection with its consideration of the proposed merger, and Houlihan Lokey’s analyses were among many factors considered by the

Special Committee in evaluating the proposed merger. Neither Houlihan Lokey’s opinion nor its analyses were determinative of the aggregate consideration or of the views of the special committee or PDC with respect to the proposed merger.

The following is a summary of the material valuation analyses performed in connection with the preparation of Houlihan Lokey’s opinion rendered to the special committee on June 11, 2011. The analyses summarized below include information presented in tabular format. The tables alone do not constitute a complete description of the analyses. Considering the data in the tables below without considering the full narrative description of the analyses, as well as the methodologies underlying and the assumptions, qualifications and limitations affecting each analysis, could create a misleading or incomplete view of Houlihan Lokey’s analyses.

For purposes of its analyses, Houlihan Lokey reviewed a number of financial metrics including:

Enterprise Value — generally the value as of a specified date of the relevant company’s outstanding equity securities (taking into account its outstanding warrants and other convertible securities) plus the value of its minority interests plus the value as of such date of its net debt (the value of its outstanding indebtedness, preferred stock and capital lease obligations less the amount of cash on its balance sheet).

EBITDA — generally the amount of the relevant company’s earnings before interest, taxes, depreciation and amortization for a specified time period.

Unless the context indicates otherwise, enterprise values used in the selected companies analysis described below were calculated using the closing price of the common stock of the selected companies listed below as of June 7, 2011, and the transaction value for the companies used in the selected transactions analysis described below were calculated as of the announcement date of the relevant transaction based on the publicly disclosed terms of the transaction and other publicly available information. Estimates of EBITDA for the Limited Partnership were based on estimates provided by PDC. Estimates of EBITDA for the selected companies listed below were based on publicly available research analyst estimates for those companies, adjusted for certain non-recurring items.

Discounted Cash Flow Analysis

Houlihan Lokey also calculated the net present value of the Limited Partnership’s unlevered, after-tax cash flows based on the projections provided by PDC, which were based on certain oil and gas reserve reports prepared by PDC’s independent oil and gas reserve engineers, applying New York Mercantile Exchange strip pricing as of June 7, 2011. In performing this analysis, Houlihan Lokey used discount rates ranging from 14.5% to 17.5% based on the Limited Partnership’s weighted average cost of capital. The discounted cash flow analyses indicated an implied reference range per limited partnership unit of $3,339 to $3,867, as compared to the proposed consideration of $4,024 per limited partnership unit.

Selected Companies Analysis

Houlihan Lokey calculated the multiples of enterprise value to certain financial metrics for the selected companies in the oil and natural gas industry.

The calculated multiples included:


	•	Enterprise Value as a multiple of 2011E EBITDA;

	•	Enterprise Value as a multiple of Proved Reserves; and

	•	Enterprise Value as a multiple of Daily Production.

The selected companies were selected because they were deemed to be similar to the Limited Partnership in one or more respects which included nature of business, size, diversification, financial performance and geographic concentration. No specific numeric or other similar criteria were used to select the selected companies and all criteria were evaluated in their entirety without application of definitive qualifications or limitations to individual criteria. As a result, a significantly larger or smaller company with substantially similar lines of businesses and business focus may have been included while a similarly sized company with less similar lines of business and greater diversification may have been excluded. Houlihan Lokey identified a sufficient number of companies for

purposes of its analysis but may not have included all companies that might be deemed comparable to the Limited Partnership. The selected companies were:


	Enterprise Value as a Multiple of
	2011 E	Proved		Daily
	EBITDA	Reserves		Production(1)

Cabot Oil & Gas Corp.	10.4x	$	2.57	$	19.38
Berry Petroleum Co.	6.7x		2.26		18.74
Bill Barrett Corp.	5.0x		2.13		9.02
Warren Resources Inc.	7.6x		2.50		11.33
Gasco Energy Inc.	Not Available		1.63		5.80
Double Eagle Petroleum Co.	Not Available		1.30		5.94
Petroleum Development Corporation	6.3x		1.24		10.36


(1)		Daily production based on the average annual production as reported in the each of the selected companies’ latest quarterly report.

The selected companies analysis indicated the following:


	Enterprise Value as a Multiple of
	2011 E	Proved		Daily
	EBITDA	Reserves		Production(1)

Low	5.0x	$	1.24	$	5.80
High	10.4x		2.57		19.38
Median	6.7x		2.13		10.36
Mean	7.2x		1.95		11.51


(1)		Daily production based on the average annual production as reported in the each of the selected companies’ latest quarterly report.

Houlihan Lokey applied multiple ranges based on the selected companies analysis to corresponding financial data for the Limited Partnership, including 6.00x to 7.00x 2011E EBITDA, $1.75 to $2.25 Proved Reserves and $10.00 to $11.00 last twelve months, or LTM, Daily Production, based on financial information and projections provided by PDC, to calculate implied limited partnership unit reference ranges. The selected companies analysis indicated (i) an implied reference range of $1,909 to $2,227 per limited partnership unit based on the Limited Partnership’s 2011E EBITDA, (ii) an implied reference range of $4,869 to $6,260 per limited partnership unit based on the Limited Partnership’s Proved Reserves, (iii) an implied reference range of $3,779 to $4,157 per limited partnership unit based on the Limited Partnership’s LTM Daily Production, in each case as compared to the proposed consideration of $4,024 per limited partnership unit.

Selected Transactions Analysis

Houlihan Lokey calculated multiples of enterprise value to certain other financial data based on the purchase prices paid in selected publicly-announced transactions involving target companies in the oil and gas industry that it deemed relevant.

The calculated multiples included:


	•	Transaction Value as a multiple of Proved Reserves; and

	•	Transaction Value as a multiple of Daily Production.

The selected transactions were selected because the target companies were deemed to be similar to the Limited Partnership in one or more respects including the nature of their business, size, diversification, financial performance and geographic concentration. No specific numeric or other similar criteria were used to select the selected transactions and all criteria were evaluated in their entirety without application of definitive qualifications or limitations to individual criteria. As a result, a transaction involving the acquisition of a significantly larger or smaller company with substantially similar lines of businesses and business focus may have been included while a

transaction involving the acquisition of a similarly sized company with less similar lines of business and greater diversification may have been excluded. Houlihan Lokey identified a sufficient number of transactions for purposes of its analysis, but may not have included all transactions that might be deemed comparable to the proposed transaction. The selected transactions were:


Date			Transaction Value as a Multiple of:
Announced	Acquiror	Target	Proved Reserves		Daily Production
			($/Mcfe)		($ (In 000s)/Mcfe/d)

5/25/2011	Synergy Resources Corp	Petroleum Exploration and Management LLC	$	1.19
9/23/2010	North Western Corporation	Undisclosed private company	$	1.50	$	8.36
9/15/2010	Denbury Resources Incorporated	Undisclosed	$	0.08
7/21/2010	Double Eagle Petroleum Company	SM Energy Company	$	0.87
6/29/2010	Enerplus Resources Fund	Undisclosed			$	10.00
5/13/2010	China Investment Corporation Ltd	Penn West Energy Trust	$	4.16	$	13.45
5/13/2010	Gulfport Energy Corporation	Undisclosed private company	$	1.44	$	28.70
3/18/2010	Opon International LLC	Delta Petroleum Corporation	$	1.33	$	9.73
1/5/2010	Noble Energy Incorporated	Suncor Energy Incorporated	$	1.22	$	6.38
11/9/2009	Rise Energy Ltd	Teton Energy Corporation	$	0.71	$	2.94
8/10/2009	Williams Companies Inc.	Orion Energy Partners	$	0.65	$	4.03
4/23/2009	Puckett Land Company	Teton Energy Corporation			$	2.51
4/2/2009	Noble Energy Incorporated	Teton Energy Corporation			$	1.33
3/3/2009	Undisclosed	Berry Petroleum Company	$	1.11	$	7.78
2/23/2009	Longview Fund LP	South Texas Oil Company	$	3.20	$	38.58
10/10/2008	SandRidge Energy Inc.	Tom L. Ward	$	1.40
9/25/2008	Occidental Petroleum Corporation	Plains Exploration & Production Co.	$	2.26	$	16.07
12/31/2007	Tracinda Corp	Delta Petroleum Corporation	$	1.59	$	10.25
12/17/2007	Occidental Petroleum Corporation	Plains Exploration & Production Co.	$	2.81	$	19.14
9/26/2007	Teton Energy Corporation	Delta Petroleum Corporation			$	5.00
9/26/2007	Delta Petroleum Corporation	Teton Energy Corporation			$	15.20
5/14/2007	Newfield Exploration Company	Stone Energy Corporation	$	2.63	$	13.14
4/18/2007	Plains Exploration Company	Laramie Energy LLC	$	2.13	$	22.69
1/7/2007	Forest Oil Corporation	The Houston Exploration Company	$	2.42	$	7.84
12/31/2006	Quantum Resources Management LLC	Pioneer Natural Resources Company	$	1.48	$	8.71


Date			Transaction Value as a Multiple of:
Announced	Acquiror	Target	Proved Reserves		Daily Production
			($/Mcfe)		($ (In 000s)/Mcfe/d)

12/12/2006	Petroleum Development Corporation	EXCO Resources Incorporated	$	3.64
10/20/2006	Petroleum Development Corporation	Unioil	$	3.40	$	23.13
8/9/2006	Black Hills Corporation	Undisclosed	$	1.04	$	17.11
7/20/2006	Marathon Oil Corporation	Petroleum Development Corporation			$	1.97
6/12/2006	JANA Partners LLC	The Houston Exploration Company	$	2.70	$	8.98
5/10/2006	Individual Investor	SandRidge Energy Inc.	$	1.85	$	19.05
3/9/2006	Black Hills Corporation	Koch Exploration Company; Koch Industries Inc.	$	1.27	$	26.50
2/22/2006	Citation Oil & Gas Corporation	Meritage Energy Partners LLC	$	1.28	$	8.20
2/9/2006	Noble Energy Incorporated	United States Exploration Inc.	$	1.22	$	15.12
1/27/2006	Berry Petroleum Company	Undisclosed private company	$	3.19	$	83.00
11/16/2005	Texas American Resources Company	Undisclosed	$	1.24	$	11.67
10/31/2005	Hilcorp Energy Company; Undisclosed	Kerr-McGee Corporation	$	1.49	$	8.05

The selected transactions analysis indicated the following:


	Transaction Value as a Multiple of
	Proved		Daily
	Reserves(1)		Production(2)

Low	$	0.08	$	1.33
High		4.16		83.00
Median		1.48		10.13
Mean		1.82		14.83


(1)		Based on proved reserves disclosed in the report announcing the applicable transaction.

(2)		Based on proved production disclosed in the report announcing the applicable transaction.

The selected transactions analysis for the transactions under $100 million indicated the following:


	Transaction Value as a Multiple of
	Proved		Daily
	Reserves(1)		Production(2)

Low	$	0.71	$	1.33
High		3.40		38.58
Median		1.28		10.19
Mean		1.54		14.14


(1)		Based on proved reserves disclosed in the report announcing the applicable transaction.

(2)		Based on proved production disclosed in the report announcing the applicable transaction.

Houlihan Lokey applied multiple ranges based on the selected transactions analysis to the corresponding data for the Limited Partnership, including $1.25 to $1.75 Proved Reserves and $8.00 to $11.00 LTM Daily Production, based on financial information and projections provided by PDC, to calculate implied limited partnership unit reference ranges. The selected transactions analysis indicated an implied reference range of $3,478 to $4,869 per limited partnership unit based on the Limited Partnership’s Proved Reserves and $3,023 to $4,157 per limited partnership unit based on the Limited Partnership’s LTM Daily Production, as compared to the proposed consideration of $4,024 per limited partnership unit.

Other Matters

PDC engaged Houlihan Lokey at the request of the special committee pursuant to a letter agreement dated as of April 20, 2011 to act as the special committee’s financial advisor in connection with the proposed merger. The special committee selected Houlihan Lokey based on Houlihan Lokey’s experience and reputation and knowledge of the Limited Partnership and its industry. Houlihan Lokey is regularly engaged to render financial opinions in connection with mergers and acquisitions, financial restructurings, tax matters, ESOP and ERISA matters, corporate planning, and for other purposes. Houlihan Lokey will receive a fee for rendering its opinion which is not contingent upon the successful completion of the proposed merger. PDC has also agreed to reimburse certain of Houlihan Lokey’s expenses and to indemnify Houlihan Lokey and certain related parties for certain potential liabilities arising out of its engagement. Houlihan Lokey has received aggregate fees of approximately $250,000 for providing financial advisory services to the special committee in connection with PDC’s proposed acquisitions of the outstanding limited partnership interests in the Limited Partnership, PDC 2003-A Limited Partnership, PDC 2003-B Limited Partnership, PDC 2003-C Limited Partnership and PDC 2003-D Limited Partnership.

Houlihan Lokey and certain of its affiliates may have in the past provided investment banking, financial advisory and other financial services to PDC and other participants in the proposed merger and/or certain of their respective affiliates, for which Houlihan Lokey and such affiliates received compensation. Houlihan Lokey has in the past provided financial advisory services to the special committee in connection with transactions in which PDC acquired the outstanding limited partnership interests in PDC 2004-A Limited Partnership, PDC 2004-B Limited Partnership, PDC 2004-C Limited Partnership and PDC 2004-D Limited Partnership, for which services Houlihan Lokey received aggregate fees of approximately $400,000. Houlihan Lokey has also in the past provided financial advisory services to the special committee in connection with transactions in which PDC is seeking to acquire the outstanding limited partnership interests in PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership and Rockies Region Private Limited Partnership, three drilling partnerships of which PDC is the managing general partner, for which services Houlihan Lokey received aggregate fees of approximately $325,000. Finally, as described above, Houlihan Lokey is currently engaged to, among other things, provide financial advisory services to the special committee in connection with its proposed acquisitions of the outstanding limited partnership interests in the Limited Partnership, PDC 2003-A Limited Partnership, PDC 2003-B Limited Partnership, PDC 2003-C Limited Partnership and PDC 2003-D Limited Partnership.

Houlihan Lokey and certain of its affiliates may provide investment banking, financial advisory and other financial services to PDC, the Limited Partnership, other participants in the proposed merger or certain of their respective affiliates in the future, for which Houlihan Lokey and such affiliates may receive compensation. In addition, Houlihan Lokey and certain of its affiliates and certain of Houlihan Lokey’s and its affiliates’ respective employees may have invested in or committed to invest in the Limited Partnership, PDC other participants in the proposed merger or certain of their respective affiliates and may do so in the future. Furthermore, in connection with bankruptcies, restructurings, and similar matters, Houlihan Lokey and certain of its affiliates may have in the past acted, may currently be acting and may in the future act as financial advisor to debtors, creditors, equity holders, trustees and other interested parties (including, without limitation, formal and informal committees or groups of creditors) that may have included or represented and may include or represent, directly or indirectly, or may have been adverse to, PDC, other participants in the proposed merger or certain of their respective affiliates, for which advice and services Houlihan Lokey and such affiliates have received and may receive compensation.

In the ordinary course of business, certain of Houlihan Lokey’s affiliates, as well as investment funds in which they may have financial interests, may acquire, hold or sell long or short positions, or trade or otherwise effect transactions, in debt, equity, and other securities and financial instruments (including loans and other obligations)

of, or investments in, the Limited Partnership, PDC, or any other party that may be involved in the proposed merger and their respective affiliates or any currency or commodity that may be involved in the proposed merger.

Regulatory Approvals

No filing or registration with, notification to, or authorization, consent or approval of, any governmental entity is required in connection with the execution and delivery of the merger agreement by the partnership, PDC or the merger sub or the consummation by the partnership, PDC and the merger sub of the transactions contemplated thereby, except for the filing of this proxy statement with the SEC and the filing of a certificate of merger with the Secretary of State of the State of West Virginia and the Secretary of State of the State of Delaware.

Alternatives to the Merger

The special committee considered the following alternatives before determining to recommend the merger transaction described in this document. As discussed below, the special committee believes that the merger is the best available alternative for the partnership to maximize the value of the partnership’s property interests.

Comparison of the Merger to Continuing Operations. Because the partnership’s revenue generating properties are mature, producing properties, the special committee believes that production from those properties will continue to decline at the rate predicted in the partnership’s oil and gas engineering reserve reports. Accordingly, cash distributions from the partnership will also decline, subject to variation for changes in oil and gas prices. As of June 30, 2011, the fair value of the partnership’s derivative position was a gain of $197,404, which will transfer to PDC without recourse to the partnership. As a result, the special committee believes that the benefit of continuing operations of the partnership is offset by the increasing general and administrative costs related to continuing operations.

Fully developing all of the partnership’s properties would require substantial capital expenditures. Because of the restrictions set forth in the partnership agreement on borrowing money and making assessments on limited partnership units, the partnership would generally be unable to fund such capital expenditures without retaining all or a substantial portion of the partnership’s cash flow. This would reduce or eliminate partnership distributions to investors while the work is being conducted and paid for, and could create phantom income (reportable income for tax purposes without a corresponding cash distribution) for investors with respect to the cash used to fund the capital expenditures, although tax deductions might offset a portion of such phantom income.

The special committee also believes there is a substantial advantage to the investors in receiving a lump-sum cash payment currently. The special committee believes that the reserve values included in PDC’s calculation of the merger consideration are higher than the net present value of estimated future cash distributions to the investors from continued operations because such reserve values have not been reduced for the reimbursement of PDC’s general and administrative expenses allocable to the partnership. Furthermore, in determining such reserve values, PDC also assumed that all of the partnership’s properties will be developed and that the development will occur on a timetable that is significantly shorter than the partnership may be able to achieve. In addition, the estimates of distributions from continued operations are based upon current oil and gas prices.

Future natural gas prices are uncertain because low-cost shale plays, particularly the Marcellus shale, may set national prices going forward. These low-cost shale plays, which have experienced a large increase in development in recent years, have added significant proved reserves and increased production primarily in the eastern portion of the United States where demand is the highest. These reserves now represent a much larger part of overall natural gas reserves and production in the United States and have the potential to affect the variability of open market pricing more significantly than in the past, along with a potential oversupply situation in a downturned economy. As a result of lower natural gas prices, the high natural gas hedging prices which PDC has achieved for the partnership during the last several years are not available at this time for future periods. PDC expects that lower realized natural gas prices and declining production will result in reduced per unit distributions in the future. PDC bases its expectations as to commodity prices primarily on applicable forward prices or the forward “curve.” The forward prices or forward “curve” are prices that are published every day by national markets, such as NYMEX, related to natural gas or oil delivery in future months and years. The prices for future natural gas vary based on the geographic point of delivery, and for most partnership gas the published Colorado Interstate Gas (CIG) price is the price used

when purchasing derivatives. These hedge instruments are ultimately settled with monetary payments by one of the sides, not by delivery of the physical natural gas or oil. At the same time, PDC’s expectations regarding natural gas prices may not be accurate. Natural gas prices are highly complex and subject to significant volatility due to numerous market forces, including numerous market fundamentals such as weather, inventory levels and expectations, competition, overall demand and the availability of supply. See “Risk Factors— The estimates of proved reserves and future net revenues considered when calculating the merger value, and underlying assumptions about future production, commodity prices and costs, may be incorrect.” The partnership’s aggregate cash distributions per limited partnership unit for the twelve months ended June 30, 2011 were $50. However cash flows available for distribution per limited partnership unit were $66, thus creating an decrease in the “— due to Managing General Partner” account. PDC estimates the partnership’s aggregate cash flows available for distribution per limited partnership unit for the twelve months ending March 31, 2012 will be $327, however distributions are expected to be minimal (approximately $50 per unit) due to cash flows available for distribution being used to repay the “— due to Managing General Partner” and to partially fund the partnership’s additional Codell formation development plan. This estimate is based on the twelve month production period beginning in April 1, 2011 and ending in March 31, 2012. This estimated cash flows available for distribution is approximately $261 more than the aggregate cash distributions for the twelve months ended June 30, 2011. The increase in cash flows available for distributions is expected to result primarily from a reduction in general and administrative expenses in addition to decreases in operating expenses as a result of normal production declines and decreases in workover costs for environmental and maintenance projects. The estimate does not assume any incremental revenue or take into account additional refracturing or the withholding of distributions to develop proved undeveloped reserves. PDC believes that the estimates, assumptions and considerations made in calculating the estimated aggregate cash flows available for distribution for the twelve months ending March 31, 2012, are reasonable. The projections summarized below were also provided to Houlihan Lokey, the special committee’s financial advisor.

The following table shows the financial statement line items used to determine cash flows available for distribution. Certain non-cash items were excluded because they have no effect on the cash distributed to limited partners:


	Twelve Months Ended		Twelve Months Ending
	June 30, 2011 (Actual)		March 31, 2012 (Estimated)

Revenue(1)	$	1,350,561	$	1,251,000
Realized derivative gains (losses)(2)		124,953		8,000
Gross revenues		1,475,514		1,259,000
Operating expenses(3)		585,375		431,000
Production taxes(4)		65,719		64,000
General and administrative expenses(5)		703,534		170,000
Total costs		1,354,628		665,000
Net cash flows available for distribution(a)	$	120,886	$	594,000
General partner cash flows		24,177		118,800
Limited partner cash flows	$	96,709	$	475,200
Limited partnership units		1455.26		1455.26
Cash flows available for distribution per limited partnership unit(b)	$	66	$	327


(a)		Cash flows available for distribution represent amounts prior to any withholdings for the well refracturing program. Any amounts withheld for the refracturing program will be added back to the purchase price upon closing of the merger.


(b)		Cash flows available for distribution per limited partnership unit for the twelve months ended June 30, 2011 were $66 per limited partnership unit during this twelve month period. Due to the normal two-month delay between production and distribution and the delay in offsetting general and administrative costs against revenues, actual cash distributions for the twelve months ended June 30, 2011 were $50 per limited partnership unit. The amount “— due to Managing General Partner” increased due to PDC’s policy of delaying the offset


		of certain large expenditures against revenues until sufficient revenues are available. For the twelve months ending March 31, 2012 cash flows available for distribution are estimated to be $327 per limited partnership unit. However distributions are expected to be minimal (less than $50 per unit) due to the use of these cash flows to reduce the “— due to Managing General Partner” and to partially fund the partnership’s additional Codell formation development plan.


*(1)*	*Operating Revenue*


	•	PDC estimates that the partnership will generate $1,251,000 in revenues during the twelve months ending March 31, 2012. The partnership generated $1,350,561 in revenues during the twelve months ended June 30, 2011.


	•	The anticipated decrease in the partnership’s revenues of $99,561 is primarily expected to result from decreases in production discussed below, partially offset by the anticipated increase in realized prices.


	•	NYMEX forward pricing curves as of March 31, 2011 were used to calculate estimated revenue. The revenue for the twelve months ended June 30, 2011 was based on average pricing received for the period. The average forward strip price used in the March 31, 2012 projection was $7.11 per Mcfe compared to the average sales price realized of $5.49 per Mcfe during the twelve months ended June 30, 2011.


	•	PDC estimates that the partnership’s production will be 176,000 Mcfe during the twelve months ending March 31, 2012. The partnership produced 246,126 Mcfe during the twelve months ended June 30, 2011. The anticipated decrease in production of 70,126 Mcfe is expected to result from reduced economics for several of the Partnership’s wells in addition to normal production declines.


	•	The estimated production was obtained from an internally generated reserve report that was based on the partnership’s 2010 year-end reserve report updated for NYMEX forward pricing curves as of March 31, 2011. The partnership’s 2010 year-end reserve report was prepared by Ryder Scott, the partnership’s independent reserve engineers, and utilized information provided by management.


*(2)*	*Realized Derivative Gains*


	•	PDC estimates that the partnership will generate $8,000 in net realized gains during the twelve months ending March 31, 2012. The partnership generated $124,953 in net realized gains during the twelve months ended June 30, 2011.


	•	The expected decrease in net realized gains of $116,953 is primarily expected to result from the fact that the partnership’s future production is hedged at a significantly lower price for the remaining positions when compared to the twelve months ended June 30, 2011.


	•	Forward pricing curves as of March 31, 2011 were used to calculate realized gains and losses based on current derivative positions which settle between April 2011 and March 2012.


*(3)*	*Operating Expenses*


	•	PDC estimates that the partnership’s operating expenses will be $431,000 during the twelve months ending March 31, 2012, as compared to $585,375 for the twelve months ended June 30, 2011. Projections based on the internally generated reserve report, as described above, were used to calculate operating expenses for the twelve months ending March 31, 2012. During the twelve months ended June 30, 2011, the partnership incurred significant workover costs for environmental and maintenance projects, which increased operating costs by approximately $155,000. There are currently no workover costs planned for the twelve months ending March 31, 2012.


*(4)*	*Production Taxes*


	•	PDC estimates that the partnership’s total production tax expenses will be $64,000 during the twelve months ending March 31, 2012, as compared to $65,719 during the twelve months ended June 30, 2011. Estimated production taxes were based on current tax rates, as PDC does not anticipate a significant change in rates

through March 31, 2012. These rates were applied to the calculated revenue to arrive at the total production tax expense.


*(5)*	*General and Administrative Expenses*


	•	PDC estimates that the partnership’s total general and administrative expense will be $170,000 during the twelve months ending March 31, 2012, as compared to $703,534 during the twelve months ended June 30, 2011. The partnership’s general and administrative expenses consist of audit, income tax preparation and outside consultant fees, among other expenses. The anticipated decrease of $533,534 in general and administrative costs is expected to result from nonrecurring professional fees due to the partnership’s compliance catch-up efforts. The projected general and administrative costs for the period ending March 31, 2012 were based on internal estimates of expected recurring costs.

Regulatory, Industry and Economic Factors


	•	In making its estimates, PDC assumed that there would be no new federal, state or local regulations of the portions of the energy industry in which the partnership operates, and no new interpretations of existing regulations that would be materially adverse to the partnership’s business during the twelve months ending March 31, 2012.


	•	In making its estimates, PDC also assumed no major adverse changes in the upstream oil and gas industry or in general economic conditions during the twelve months ending March 31, 2012.

It is likely that over a long period of time, oil and gas prices will vary often and possibly widely, as has been demonstrated historically, from the prices used to prepare these estimates. Continued operations over a long period of time subject the investors to the risk of receiving lower levels of cash distributions if oil and gas prices over this period are lower on average than those used in preparing the estimates of cash distributions from continued operations. Continued operations also subject the investors’ potential distributions to the risk of possible changes in costs or need for workover or similar significant remedial work on the partnership’s properties. As a result, the special committee believes that there is an advantage to the investors in taking a lump-sum cash payment, which can be redeployed in other investments, relative to continuing to receive decreasing levels of cash distributions over a long period of time.

The partnership is subject to the informational and reporting requirements of the Securities Exchange Act of 1934 and is, as a result, required to file annual, quarterly and current reports, including current financial and other information, with the SEC. The partnership incurs significant direct and indirect costs to comply with the filing and reporting requirements as a public reporting company and the relative costs have increased over time. The substantial costs and burdens imposed on the partnership as a result of being public are likely to continue as a result of the application of Section 404(b) of the Sarbanes-Oxley Act to the partnership. Section 404 requires that the partnership’s management perform a formal assessment of our internal controls over financial reporting, including tests to confirm the design and operating effectiveness of the controls, and include in the partnership’s annual report management’s assessment of the effectiveness of our internal controls over financial reporting.

The expenses associated with the continued preparation, internal and external review and filing of such information and reports significantly increase the partnership’s general and administrative costs and, consequently, reduce the amount of cash flow available for distributions to investors and for other operational purposes. For

smaller publicly traded companies such as the partnership, these costs represent a larger portion of revenues and assets as compared to larger public companies. As a result of the monetary savings anticipated as a result of going-private, the time and capital currently devoted by management to the partnership’s public company reporting obligations could be devoted to other purposes, including operational concerns to further PDC’s business objectives.

Comparison of the Merger to Master Limited Partnership. PDC considered accomplishing the consolidation of the partnership through a master limited partnership, pursuant to which the limited partnership units of the investors would be exchanged for interests in the master limited partnership.

However, PDC has been advised that the partnership’s oil and gas properties are not of sufficient size in the aggregate to attract new capital through a master limited partnership. In addition, the partnership interests in a master limited partnership might not be traded on a national stock exchange or in any other significant market. Some master limited partnership interests might be sold from time to time in private or over-the-counter transactions, but the prices would likely reflect a discount for illiquidity. As a result, a master limited partnership might not provide the investors with immediate and complete liquidity for their investment in the partnership. In addition, a master limited partnership would still be burdened with general and administrative expenses, including the expenses associated with meeting the reporting requirements of the Securities Exchange Act of 1934, which would reduce any cash distributions paid to the investors of the master limited partnership.

Comparison of the Merger to Negotiated Third Party Sale. The special committee also considered whether the partnership would benefit from attempting to sell its property interests in negotiated transactions. However, any buyer would be purchasing many property interests that they would neither control nor operate. A portion of the properties in which the partnership owns interests would likely continue to be operated by PDC because PDC controls other interests in fields in which the partnership’s properties are located. PDC’s control of such properties could negatively affect the amount a third party would be willing to pay and the overall interest of third parties in buying such properties. Because of PDC’s control of such properties, the special committee believes that PDC is the party in the position to pay the highest price for such interests and the one most likely to do so.

In addition, sale of the partnership’s properties on a direct basis often involves substantial periods of time for due diligence, negotiation and execution of agreements and closings, often with different purchasers for different properties. Satisfying due diligence requests requires large amounts of time to create and supervise data rooms or disseminate data to possible purchasers, plus the time needed to deal directly with multiple prospective purchasers. Furthermore, some issues, such as environmental and title matters, may come to light in the late stages of a negotiated sale, which may delay or preclude the consummation of the sale.

The transaction costs for offering properties in a negotiated sale could be substantial. Those costs include:


	•	preparing and disseminating information on properties to be offered;

	•	soliciting attendance by prospective purchasers; and

	•	screening and qualifying purchasers.

Comparison of the Merger to Tender Offer. PDC considered accomplishing the consolidation of the partnership through a tender offer, pursuant to which PDC would offer to purchase all of the investors’ limited partnership units. In connection with a tender offer, each investor would have the option to accept or reject PDC’s offer to purchase such investor’s units, irrespective of whether the other investors were to accept or reject such offer with respect to their units. If any of the investors were to fail to accept the tender offer (and therefore fail to sell their limited partnership units to PDC in connection with such tender offer), such investors’ units would remain outstanding and, as a result, the partnership would remain subject to some or all of the administrative and other burdens and expenses associated with the continued operation of the partnership, as more fully described above. This would be true even if investors holding a majority (but less than all) of the outstanding partnership units were to accept the tender offer.

In connection with the proposed merger transaction, however, whether the investors vote to approve or reject the amendment and/or the merger agreement proposals, every investor will be bound by the vote. If the merger

agreement is approved by holders of a majority of the outstanding limited partnership interests held by the investors, then upon consummation of the merger:


	•	the merger sub will be the surviving entity;

	•	the separate existence of the partnership as a business entity will cease;

	•	all investors will be required to exchange their limited partnership units for the cash payment described in this proxy statement, including those investors who voted against approving the merger agreement (subject to the valid exercise of appraisal rights); and

	•	PDC will hold all of the equity interests in the merger sub.

Third-Party Offers

None of the partnership affiliates, the partnership or the special committee has received any offer from any third party to acquire the partnership or its assets. None of the partnership affiliates, the partnership or the special committee has solicited or arranged for other parties to solicit third party offers with respect to the sale of the partnership.

Effects of the Merger

The merger will involve the merger of the partnership with and into the merger sub, an exchange of cash consideration for the limited partnership units held by investors, and all of PDC’s interest in the partnership (including, without limitation, its managing general partner interest and all limited partnership units held by PDC or any of its affiliates) shall be extinguished. As a result of the merger, the investors will have no continuing interest in the partnership. Following the merger, there will be no trading market for the limited partnership units, and no further distributions will be paid to the former investors. In addition, following the consummation of the merger, the registration of any limited partnership units under the Securities Exchange Act of 1934 will be terminated. Upon completion of the merger, the merger sub shall be the surviving entity, the partnership will cease as a separate business entity, and PDC shall hold all of the interests in the merger sub.

Effect on Net Book Value and Net Earnings of PDC and Merger Sub

If the merger is completed, the investors will have no interest in the surviving company’s net book value or net earnings after the merger. The table below sets forth the interest of each of PDC, merger sub and the affiliated officers in the partnership’s net book value and net earnings prior to and immediately following the proposed merger transaction, based on the partnership’s net book value as of June 30, 2011, and the net income of the partnership for the six months ended June 30, 2011.


	Ownership Prior to the Merger											Ownership After the Merger⁽²⁾
	Net Book Value					Net Earnings						Net Book Value					Net Earnings
	$ (in					$ (in						$ (in					$ (in
	thousands)		%			thousands)			%			thousands)		%			thousands)			%

PDC	$	1,484		27.87	%	$	(54	)		27.87	%	$	5,325		100	%	$	(195	)		100	%
Merger Sub		—		0	%		—			0	%	$	5,325		100	%	$	(195	)		100	%
Affiliated Officers⁽¹⁾		—		0	%		—			0	%		—		0	%		—			0	%


(1)		The affiliated officers have equity interests in PDC through stock ownership, stock options and other stock based compensation, but do not have direct financial or equity interests in the partnership or the merger sub.

(2)		Merger sub, the surviving company upon consummation of the merger, is a wholly-owned subsidiary of PDC.

Conflicting Duties of PDC, Individually and as the General Partner

In considering the recommendations with respect to the merger of the special committee, on behalf of PDC in its capacity as managing general partner of the partnership, the investors should be aware that PDC has interests in the merger that are different from, or in addition to, the interests of the investors generally. PDC, as managing general partner of the partnership, has a duty to manage the partnership in the best interests of the limited partners of

the partnership. However, PDC also has a duty to operate its business for the benefit of its shareholders. Consequently, PDC’s duties to its shareholders may conflict with its duties to the investors.

PDC and its board of directors have attempted to formally address the conflicts inherent in the relationships among PDC, the partnership and the officers and directors of PDC by forming the special committee (consisting of four non-employee members of PDC’s board, namely Anthony J. Crisafio, Larry Mazza, David C. Parke and Jeffrey C. Swoveland), which has been authorized, among other things:


	•	to act on behalf of PDC’s board in representing the interests of the partnership and its investors with respect to all matters relating to the merger or any related or alternative transactions thereto; and

	•	to exercise all lawfully delegable powers of PDC’s board (acting in its capacity as the governing decision-making body of the managing general partner on behalf of the partnership) to take any and all actions and to make any and all decisions relating to the merger or any related or alternative transactions thereto, including without limitation the consideration, evaluation, negotiation, rejection or acceptance thereof, all on behalf of the partnership, and as the special committee deems to be advisable and in the best interests of the partnership and its investors.

In addition, each of the members of the special committee has abstained and will abstain in the future from any vote of PDC’s board of directors with respect to the merger on behalf of PDC. However, because each of the members of the special committee is also a member of PDC’s board of directors, notwithstanding the creation of the special committee, an inherent conflict continues to exist with respect to each committee member’s duties to the investors in his capacity as a member of the special committee, on the one hand, and such member’s duties to the shareholders of PDC in his capacity as a member of PDC’s board of directors, on the other hand. The creation of the special committee and the abstention by its members from any board vote regarding a merger on behalf of PDC may lessen the inherent conflicting interests of PDC’s directors in this transaction. However, establishment of a special committee cannot entirely eliminate the inherent conflicting interests of PDC’s directors in this transaction. In addition, no committee or other entity independent of PDC and its board of directors was formed or engaged to negotiate on your or the partnership’s behalf. No representative group of investors and no outside experts or consultants, such as investment bankers, legal counsel, accountants or financial experts, were engaged solely to represent the independent interests of the investors in structuring and negotiating the terms of the merger. The investors will be entitled to access PDC’s and the partnership’s corporate records in the manner permitted by applicable federal and Nevada and West Virginia state laws. Neither PDC nor the partnership has made any other provision to grant the investors access to the corporate records of PDC or the partnership, or for the investors to obtain counsel or appraisal services at PDC’s or the partnership’s expense.

PDC believes, however, that the steps that it has taken have enabled PDC’s directors to more effectively consider and focus on the separate interests of the partnership and its investors, on the one hand, and PDC and its shareholders, on the other hand.

Financial Interests of Officers and Directors

The officers and directors of the merger sub and PDC have equity interests in PDC through stock ownership, stock options and other stock-based compensation, but do not have direct financial or equity interests in the partnership. The board of directors of PDC, in its individual capacity and in its capacity as sole member of the merger sub, believes that any economic benefit their respective officers and directors may obtain from the merger will be modest and will not result in a material economic benefit to such officers and directors.

Termination of Registration and Reporting Requirements

As a result of the merger, the limited partnership units in the partnership, as well as the partnership itself, will cease to exist. Consequently, PDC intends to terminate:


	•	registration of the limited partnership units of the partnership under the Securities Exchange Act of 1934; and

	•	the partnership’s obligations to file reports and other information under the Securities Exchange Act of 1934.

Material U.S. Federal Income Tax Consequences

This summary of the anticipated material U.S. federal income tax consequences of the merger is based upon current law and is not a complete discussion of all possible tax consequences of the merger. It does not address any state, local or foreign tax considerations, nor does it discuss all of the aspects of U.S. federal income taxation that may be relevant to specific investors in light of their particular circumstances. The discussion below focuses on the U.S. federal income tax considerations applicable to individuals who are citizens or residents of the United States. Future legislative, judicial or administrative changes or interpretations could alter or modify the following statements and conclusions, and any of these changes or interpretations could be retroactive and could cause the tax consequences to vary substantially from the consequences described below.

You are urged to consult your own tax advisor to determine all of the relevant federal, state and local tax consequences of the merger particular to you. The following discussion is not intended as a substitute for careful tax planning, and you must depend upon the advice of your own tax advisor concerning the effects of the merger.

Tax Treatment of the Merger. If the merger is completed as contemplated, the partnership will merge with and into merger sub and an investor’s limited partnership units will be converted into the right to receive a cash payment. For U.S. federal income tax purposes, the exchange by an investor of limited partnership units for cash pursuant to the merger will be a taxable transaction that is expected to be treated as a sale of limited partnership units by an investor in exchange for the cash payment.

Recognition of Gain or Loss. An investor will generally recognize gain or loss in the merger equal to the difference between the unitholder’s “amount realized” and the investor’s tax basis for the limited partnership units immediately prior to the merger. An investor’s amount realized will include the cash payment plus the investor’s share of any of the partnership’s liabilities assumed by the merger sub in connection with the merger.

Gain or loss recognized by an investor on the sale of a limited partnership unit held for more than one year will generally be taxable as capital gain or loss. However, a portion of this gain or loss, which may be substantial, that is treated as “recapture” of previously deducted intangible drilling costs, depletion, or depreciation will be separately computed and taxed as ordinary income. An investor’s share of the partnership’s syndication costs that were not allowed as a deduction in the partnership’s initial tax year will generally become deductible as a capital loss by the investor as a result of the merger. Under Section 469 of the Internal Revenue Code, any losses from the partnership that have been suspended under the passive loss rules will become fully deductible as a result of the merger.

Tax Rates. Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 15%. Absent new legislation extending the current rates, marginal tax rates for U.S. federal income tax purposes will increase in 2013. Capital losses are deductible only to the extent of capital gains, except that non-corporate taxpayers may deduct up to $3,000 of capital losses in excess of the amount of their capital gains against ordinary income. Excess capital losses generally can be carried forward to succeeding years.

Accounting Treatment

Upon completion of the merger, the separate existence of the partnership as a business entity will cease. PDC will account for the merger under purchase accounting in accordance with FASB Accounting Standards

Codification 805 (“ASC 805”), “Business Combinations.” Under ASC 805, the merger sub will record the assets and liabilities of the partnership on its books at their estimated fair market values.

Sources of Funds

PDC will need approximately $5.3 million in cash to complete the merger. PDC will finance the merger by borrowing funds under its revolving credit facility. There are no material conditions to PDC’s ability to obtain the funds through the revolving credit facility. PDC has established no alternative financing arrangements besides the aforementioned. PDC expects to repay borrowings from the credit facility with cash from operations in the ordinary course of business or capital market transactions.

PDC operates under a credit facility dated as of November 5, 2010, as amended last on May 6, 2011, with an aggregate revolving commitment or borrowing base of $350 million. The maximum allowable facility amount is $600 million. The credit facility is with certain commercial lending institutions and is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit.

PDC’s credit facility borrowing base is subject to size redetermination semiannually based on a valuation of PDC’s reserves at December 31 and June 30 and is also subject to a redetermination upon the occurrence of certain events. The borrowing base of the credit facility will be the loan value assigned to the proved reserves attributable to PDC’s natural gas and crude oil interests, excluding proved reserves attributable to PDC Mountaineer, LLC and PDC’s 26 affiliated public partnerships. The credit facility is secured by a pledge of the stock of certain of PDC’s subsidiaries, mortgages of certain producing natural gas and crude oil properties and substantially all of PDC’s other assets. Neither PDC Mountaineer, LLC nor the various limited partnerships that PDC has sponsored and continues to serve as the managing general partner are guarantors of the credit facility.

PDC’s outstanding principal amount accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greater of JPMorgan Chase Bank, N.A.’s prime rate, the federal funds rate plus a premium and 1-month LIBOR plus a premium), or at PDC’s election, a rate equal to the rate for dollar deposits in the London interbank market for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with PDC’s utilization of the facility. No principal payments are required until the credit agreement expires on November 5, 2015, or in the event that the borrowing base would fall below the outstanding balance. The credit facility contains covenants customary for agreements of this type.

Through May 26, 2011, PDC had outstanding an undrawn $18.7 million irrevocable standby letter of credit in favor of a third party transportation service provider. This letter of credit reduced the amount of available funds under PDC’s credit facility by an equal amount. PDC paid a fronting fee of 0.125% per annum and an additional quarterly maintenance fee equivalent to the spread over Eurodollar loans (2.0% per annum as of May 26, 2011) for the period the letter of credit remained outstanding. The letter of credit was originally set to expire on May 22, 2012. On May 27, 2011, PDC was required to replace the original letter of credit with a new letter of credit. As of June 30, 2011, for administrative reasons, the new letter of credit was not yet final; however, it was completed and outstanding as of July 25, 2011. There were no significant changes from the original letter of credit.

As of June 30, 2011, PDC had drawn $8.5 million from their credit facility compared to no outstanding draws as of December 31, 2010. PDC pays a fee of 0.5% per annum on the unutilized commitment on the available funds under their credit facility. As of June 30, 2011, the available funds under PDC’s credit facility, assuming the $18.7 million irrevocable standby letter of credit was in effect, were $322.8 million. The weighted average borrowing rate on PDC’s credit facility was 0.7% per annum as of June 30, 2011.

Payment of Expenses and Fees

PDC is soliciting your proxy pursuant to this document. Whether or not the merger is consummated, all costs and expenses incurred by PDC, the partnership, the merger sub and the affiliated officers in connection with the merger agreement and the transactions contemplated thereby (including without limitation the solicitation of proxies in connection therewith) shall be paid by PDC. PDC will reimburse fiduciaries, nominees and others for their out-of-pocket expenses in forwarding proxy materials to investors. PDC (acting in its capacity as the managing general partner of the partnership and pursuant to the authority and direction of the special transaction committee)

has retained PDC Securities Incorporated to assist in the solicitation of proxies from holders of limited partnership units.

PDC Securities Incorporated, which we refer to as PDC Securities, was the dealer-manager for the partnership’s public offering of limited partnership units in 2002. PDC Securities is a wholly owned subsidiary of PDC. Two of its former employees will assist in the solicitation of proxies from holders of limited partnership units and be available to answer questions raised by the broker-dealer home offices and the selling representatives who previously sold these limited partnership units. If each of the amendment to the partnership agreement and the merger transaction is approved by holders of a majority of the outstanding limited partnership units held by the investors, PDC will pay these two former employees a commission equal to 1.5% of the aggregate merger consideration for their services and will reimburse them for any expenses they incur. If either the amendment to the partnership agreement or the merger transaction is not approved, then the two former employees will not receive any commission or fee other than reimbursement for any expenses they incurred in connection with their solicitation of proxies from holders of limited partnership units. Other employees of PDC Securities are full-time employees of PDC and will assist in the solicitation of proxies but will not receive any additional compensation for their solicitation efforts.

In addition to solicitation by use of the mail, directors, officers and employees of PDC may solicit proxies in person or by telephone or other means of communication. The directors, officers and employees will not receive additional compensation, but may be reimbursed for reasonable out-of-pocket expenses incurred in connection with the solicitation.

PDC estimates that the expenses and fees for the merger will be as follows:


Filing fee with SEC	$	613
Legal, accounting, financial advisor and other consulting fees		139,000
Printing and mailing fees		60,000
Solicitation and tabulation expenses		104,185
Miscellaneous		10,000

Total expenses	$	313,798

RISK FACTORS

YOU SHOULD CAREFULLY CONSIDER THE FOLLOWING RISK FACTORS IN DETERMINING WHETHER TO VOTE TO APPROVE THE MERGER.

UPON CONSUMMATION OF THE MERGER, THE INVESTORS’ LIMITED PARTNERSHIP UNITS (OTHER THAN LIMITED PARTNERSHIP UNITS OWNED BY INVESTORS WHO PROPERLY EXERCISE APPRAISAL RIGHTS) WILL BE CONVERTED INTO THE RIGHT TO RECEIVE CASH, WHICH WE REFER TO IN THE AGGREGATE AS THE MERGER VALUE. WE DO NOT EXPECT THAT THE ESTIMATES USED TO CALCULATE THE MERGER VALUE AS OF THE DATE OF THE DEFINITIVE PROXY STATEMENT WILL BE ADJUSTED.

The estimates of proved reserves and future net revenues considered when calculating the merger value, and underlying assumptions about future production, commodity prices and costs, may be incorrect.

The calculations of the partnership’s proved reserves of crude oil, natural gas liquids and natural gas and future net revenues from those reserves included in this document are only estimates. The accuracy of any estimate is a function of:


	•	the quality of available data;

	•	engineering and geological interpretation and judgment regarding future production levels of oil, natural gas liquids and natural gas;

	•	assumptions about future quantities of recoverable oil, natural gas liquids and natural gas reserves and operating expenses related thereto;

	•	the timing of and actual level of success realized in the development of non-producing reserves;

	•	assumptions about prices for crude oil, natural gas liquids and natural gas; and

	•	assumptions about costs to extract and process, if necessary, crude oil, natural gas liquids and natural gas and to transport them to their point of sale.

When determining the amount of merger consideration to offer pursuant to the merger agreement, PDC estimated the partnership’s proved reserves was based on a future production curve consistent with the production curves used in the partnership’s reserve report as of December 31, 2010, with the addition of estimated future production attributable to undeveloped projects. Actual production may vary from that assumed production. In addition, actual prices in the future may be materially higher or lower than those used in the calculation of the merger value, even though PDC adjusted the estimated future net revenues for standard industry price adjustments, including:


	•	production costs;

	•	the effects of oil quality;

	•	British thermal unit, or BTU, content for gas;

	•	oil and gas gathering and transportation costs; and

	•	gas processing costs and shrinkage.

Therefore, the estimated future net revenues considered in the calculation of the merger value may differ materially from actual revenues received in the future from the partnership’s properties. In addition, actual future net revenues will be affected by:


	•	the timing of production and related expenses;

	•	changes in consumption; and

	•	changes in governmental regulations or taxation (and the costs and expenses related thereto).

The discount rates considered in the calculation of the merger value might not reflect the actual cost of capital in effect from time to time and the risks associated with the partnership’s properties or the oil and gas industry in general. The discount rates may disfavor longer-lived properties when compared to shorter-lived properties.

Actual prices, production, operating expenses and quantities of recoverable oil and natural gas reserves may vary from those assumed in the estimates considered for purposes of calculating the merger value. The variances may be significant. Any significant variance from the assumptions used could result in the actual quantity of the partnership’s reserves and future net revenues being materially different from the estimates in the partnership’s reserve reports and in the calculation of the merger value. In addition, changes in production levels and changes in crude oil, natural gas liquids and natural gas prices after the date of the estimate may result in substantial upward or downward revisions to estimated reserves, but we do not expect that the merger value will be adjusted to reflect such revisions.

The merger value might not reflect the value of the partnership’s assets.

Since the merger value is based on assumptions about reserves, production, commodity prices and costs that may prove to be incorrect, the merger value could vary materially from the current market value of, or the price that a third party might offer for, the partnership’s estimated oil and gas reserves and from the value given to the partnership’s actual future net revenues. The assumptions used to determine the merger value might not properly reflect the value of the partnership’s assets. In that case, partners could receive less than a fair market price for their partnership interests. For a description of other methods of determining merger value, see “Method of Determining Merger Value and Amount of Cash Offered — Components of Merger Value.”

PDC does not expect that the merger value will be adjusted for changes before the completion of the merger.

The amount of cash you will receive in the merger is based on the merger value. The merger value was determined based on data as of July 1, 2011 and after filing the definitive proxy statement, PDC does not expect that the merger value will change other than for the addition of the sum of the amounts withheld from per unit cash distributions by the partnership from October 1, 2010 through August 31, 2011 for the partnership’s additional Codell formation development plan and the subtraction of the per unit cash distributions made after August 31, 2011. For example, although oil and gas prices have fluctuated significantly in the recent past and may continue to do so, PDC anticipates that the merger value will not be adjusted between the date of filing of the definitive proxy statement and the closing date of the merger (with the exception of the addition of the sum of the amounts withheld from per unit cash distributions by the partnership from October 1, 2010 through August 31, 2011 for the partnership’s additional Codell formation development plan and the subtraction of the per unit cash distributions made after August 31, 2011) to reflect any general changes in oil or gas prices, any other matter generally affecting the oil and gas industry, or any revisions to, or new information regarding, the partnership’s reserve, production, price or cost estimates occurring after the date of filing the definitive proxy statement and prior to the closing date of the merger.

You were not independently represented in establishing the terms of the merger.

PDC and the merger sub established the terms of the merger, including the merger value and the method for determining the merger value. As noted elsewhere in this proxy statement, PDC’s board of directors had conflicting interests in evaluating the merger. Moreover, although the special committee was formed to negotiate the terms of the merger on behalf of the partnership and its investors (while abstaining from any board vote with respect to the merger on behalf of PDC), no committee or other entity independent of PDC and its board of directors was formed or engaged to negotiate on your or the partnership’s behalf. No representative group of investors and no outside experts or consultants, such as investment bankers, legal counsel, accountants or financial experts, were engaged solely to represent the independent interests of the investors in structuring and negotiating the terms of the merger. If you had been separately represented, the terms of the merger might have been different and possibly more favorable to you.

The interests of PDC, the merger sub and their directors and officers may differ from your interests.

In considering the recommendations with respect to the merger of the special committee, on behalf of PDC in its capacity as managing general partner of the partnership, you should be aware that PDC has interests in the merger that are different from, or in addition to, the interests of the investors generally. PDC, as the managing general partner of the partnership, has a duty to manage the partnership in the best interests of the limited partners of the partnership. However, PDC also has a duty to operate its business for the benefit of its shareholders. Consequently, PDC’s duties to its shareholders may conflict with its duties to the investors.

Because each of the members of the special committee is also a member of PDC’s board of directors, notwithstanding the creation of the special committee, an inherent conflict continues to exist with respect to each committee member’s duties to the investors in his capacity as a member of the special committee, on the one hand, and such member’s duties to the shareholders of PDC in his capacity as a member of PDC’s board of directors, on the other hand. The creation of the special committee and the abstention by its members from any board vote regarding a merger on behalf of PDC may lessen the inherent conflicting interests of PDC’s directors in this transaction. However, establishment of a special committee cannot entirely eliminate the inherent conflicting interests of PDC’s directors in this transaction.

You should also be aware that the merger sub has interests in the merger that are different from, or in addition to, the interests of the investors generally. The merger sub is a direct, wholly-owned subsidiary of PDC and was formed solely for the purpose of effecting the merger. The officers of the merger sub have equity interests in PDC through stock ownership, stock options and other stock-based compensation, but do not have direct financial or equity interests in the partnership. Consequently, any action by PDC, as sole member of the merger sub, may result in conflicts of interest similar to those described above.

PDC has not previously offered the partnership for sale to others, and did not solicit any third-party offers.

Although the partnership may have sold immaterial individual properties from time to time in the ordinary course of its business, PDC has not previously tried to sell the partnership, as a whole, to third parties. As a result, PDC and the special committee cannot be sure what the market demand is for the partnership’s properties, as a whole, or what a third party would offer for the partnership. In addition, PDC has not solicited third-party offers to purchase the partnership or its assets, and no assurance can be given that the terms of the merger are as favorable as those that could be obtained from a sale of the partnership or its assets to an unrelated party. The special committee will consider offers to purchase the partnership or its assets from third parties, but there might not be any third-party offers or, to the extent an offer is made, the special committee might not consider that offer to be a viable alternative to the merger.

Third parties might not make an offer for the partnership if they cannot become operator of the partnership’s properties.

PDC operates all or almost all of the partnership’s wells on behalf of the partnership and others who own interests in those wells, including PDC. Although the special committee will consider other offers for the partnership or its assets, PDC is not offering to sell the rights to operate the partnership’s properties. Consequently, potential buyers may not be interested in making an offer to acquire the partnership if they cannot also acquire operating rights to the partnership’s properties.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This proxy statement contains forward-looking statements. These forward-looking statements are not based on historical facts, but rather are based on current expectations, estimates and projections. Words such as “anticipates,” “expects,” “intends,” “plans,” “believes,” “seeks,” “could,” “should,” “will,” “projects,” “estimates” and similar expressions are intended to identify forward-looking statements. These statements are not guarantees of future performance and are subject to risks, uncertainties and other factors, some of which are beyond PDC’s or the partnership’s control, are difficult to predict and could cause actual results to differ materially from those expressed or forecasted in the forward-looking statements. In that event, the partnership’s business, financial condition or results of operations could be materially adversely affected, and investors could lose part or all of their investment. Important factors, risks and uncertainties that may cause actual results to differ from those expressed in our forward-looking statements include, but are not limited to:


	•	changes in political and general economic conditions, including the economic effects of terrorist attacks against the United States and elsewhere and related events;

	•	changes in financial market conditions, either nationally or locally in areas in which the partnership or PDC conducts its operations;

	•	fluctuations in the oil and gas markets;

	•	changes in interest rates;

	•	changes in fiscal, monetary, regulatory, trade and tax policies and laws, including policies of the Internal Revenue Service;

	•	new litigation or changes in existing litigation;

	•	increased competitive challenges and pricing pressures among petroleum companies;

	•	inflation and deflation;

	•	legislation or regulatory changes, which adversely affect the ability of the partnership and PDC to conduct the businesses in which they are engaged;

	•	future cash distributions to investors;

	•	PDC and the partnership’s ability to comply with applicable laws and regulations; and

	•	changes in accounting policies, procedures or guidelines as may be required by the Financial Accounting Standards Board or regulatory agencies.

In addition, the closing of the merger described in this proxy statement is subject to various conditions, including the receipt of the affirmative vote of the holders of a majority of the outstanding limited partnership units held by the investors and other customary closing conditions. No assurances can be given that the proposed transaction will be consummated on the terms contemplated or at all.

The forward-looking statements in this proxy statement are made as of the date hereof, and we do not assume any obligation to update, amend, or clarify them to reflect events, new information, or circumstances occurring after the date hereof except as required by applicable federal securities laws. A Schedule 13E-3 filed with the SEC with respect to the proposed merger will be amended to report any material changes in the information set forth in the most recent Schedule 13E-3 filed with the SEC.

You should rely only on the information contained in this document in deciding whether to vote for the amendment to the partnership agreement and the merger. The appendices constitute an integral part of this document. Please carefully read all of the appendices. We have not authorized anyone to provide you with information that is different from what is contained in this document. This document is dated September 12, 2011. You should not assume that the information contained in this document is accurate as of any date other than such date.

Notwithstanding any statement made in this proxy statement or in any document incorporated herein by reference, the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 do not apply to statements made in connection with the proposed going-private merger transaction.

THE SPECIAL MEETING

Date, Time and Place

The special meeting of the investors will be held on October 28, 2011, at 10:00 a.m., Mountain Time, at 1775 Sherman Street, Suite 3000, Denver, Colorado 80203.

Purpose of the Special Meeting

The purpose of the special meeting, and any adjournment or postponement of the special meeting, is for the investors to consider and vote on the following matters:


	•	A proposal by PDC to amend the partnership agreement in order to grant the investors an express right to vote to approve merger transactions such as the proposed merger.

	•	A proposal by PDC to approve the Agreement and Plan of Merger, dated as of June 20, 2011, by and among the partnership, PDC and the merger sub, pursuant to which the partnership will merge with and into the merger sub, with the merger sub being the surviving entity. Upon consummation of the merger, all of the partnership’s outstanding limited partnership units (other than the limited partnership units owned by PDC or any subsidiary thereof and other than limited partnership units owned by investors who properly exercise appraisal rights) will be converted into the right to receive cash in an amount equal to $4,024 per limited partnership unit, plus the sum of the amounts withheld from per unit cash distributions by the partnership from October 1, 2010 through August 31, 2011 for the partnership’s additional Codell formation development plan, less the sum of the per unit cash distributions made after August 31, 2011 and before the transaction closes. In the event holders of less than a majority of the outstanding limited partnership units held by the investors vote to approve the amendment or the merger agreement, PDC will withdraw the offer and the merger will not proceed.

	•	Any proposal to adjourn or postpone the special meeting to a later date if necessary or appropriate, including an adjournment or postponement to solicit additional proxies if, at the special meeting, the number of limited partnership units present or represented by proxy and voting in favor of the approval of the merger agreement or the amendment to the partnership agreement is insufficient to approve the merger agreement or the amendment of the partnership agreement, respectively.

	•	Other business as may properly come before the special meeting.

Recommendation of the Special Committee

The special committee, on behalf of PDC in its capacity as the managing general partner of the partnership, has approved the merger agreement, has determined that the merger is advisable and in the best interests of the partnership and reasonably believes that the merger is fair to the investors, each of whom is unaffiliated with PDC. The special committee recommends that the investors vote for the amendment and the merger agreement. However, investors should note that PDC’s board of directors has interests in the merger that are different from, or in addition to, the interests of the investors generally. See “Risk Factors — You were not independently represented in establishing the terms of the merger,” “Risk Factors — The interests of PDC, the merger sub and their directors and officers may differ from your interests,” and “Special Factors with Respect to the Merger — Conflicting Duties of PDC, Individually and as the General Partner” for more detail.

Record Date; Voting Rights And Proxies

Only investors of record at the close of business on September 1, 2011 are entitled to notice of and to vote at the special meeting, or any adjournments or postponements thereof.

Investors of record are entitled to vote at the special meeting based on the percentage of limited partnership units they own. Each investor will be entitled to one vote for each limited partnership unit held (or a fractional vote proportional to his interest for interests of less than one limited partnership unit) on all matters to be voted upon at the special meeting.

Voting Your Limited Partnership Units

PDC, in its capacity as managing general partner of the partnership, is soliciting proxies from the investors. This will give you an opportunity to vote at the special meeting. PDC urges you to complete, date and sign the accompanying proxy card and return it promptly in the enclosed postage-paid envelope. You may also vote via the internet at http://www.pdcgas.com/castmyvote.cfm. When you deliver a valid proxy, a named agent will vote the limited partnership units represented by that proxy in accordance with your instructions. If you do not vote by proxy, vote via the internet or attend the special meeting and vote in person, your vote will not be counted, although your limited partnership units will be included in the total used to determine the number of limited partnership units required for a majority. If you vote by proxy, but make no specification on your proxy that you have otherwise properly executed, the named agent will vote FOR approval of the amendment and the merger agreement.

You may grant a proxy by dating, signing and mailing your proxy card or by voting at the internet site. You may also attend the special meeting and cast your vote in person at the meeting.

Mail. To grant your proxy by mail, please complete your proxy card and sign, date and return it in the enclosed envelope. To be valid, a returned proxy card must be signed and dated.

By Internet. You can vote via the internet at http://www.pdcgas.com/castmyvote.cfm. The internet voting system has easy to follow instructions on how you may vote your limited partnership units and allows you to confirm that the system properly recorded your vote. If you choose to vote over the internet, you will be required to enter your Unique ID. Your Unique ID is the 8-to-10 digit number found on the bottom left of the proxy card included with this proxy statement. If you vote via the internet, you do not need to return your proxy card to PDC.

In Person. If you attend the special meeting in person, you may vote your limited partnership units by completing a ballot at the meeting. Attendance at the special meeting will not by itself be sufficient to vote your limited partnership units; you still must complete and submit a ballot at the special meeting to vote your limited partnership units.

Changing Your Vote. You may change your vote at any time before the vote at the special meeting by mailing a later-dated, signed proxy card or other instrument revoking your proxy so that it is received by the time of the special meeting at the executive offices of the partnership. Investors may also change their vote by attending the special meeting and voting in person. If you choose to revoke your proxy that you had earlier mailed to PDC or if you would like to vote a new proxy, please send a new proxy card (dated as of the date you changed your vote) to Darwin Stump, PDC’s Vice President Accounting Operations, 1775 Sherman Street, Suite 3000, Denver, Colorado 80203. If you cast your vote via the internet at the web site specified above, you may also revoke or change your earlier vote by following the instructions at the web site. In addition, if you voted by proxy card, you may change your vote via the internet at the web site specified above. Likewise, if you voted via the internet, you may change your vote by submitting a later-dated proxy card.

Solicitation of Proxies and Costs

PDC, in its capacity as managing general partner of the partnership, is soliciting your proxy pursuant to this proxy statement. Whether or not the merger is consummated, all costs and expenses incurred by PDC, the partnership and the merger sub in connection with the merger agreement and the transactions contemplated thereby (including, without limitation, this solicitation of proxies) will be paid by PDC. PDC will reimburse fiduciaries, nominees and others for their out-of-pocket expenses in forwarding proxy materials to investors. PDC (acting in its capacity as the managing general partner of the partnership and pursuant to the authority and direction of the special committee) has retained PDC Securities Incorporated to assist in the solicitation of proxies from holders of limited partnership units.

will reimburse them for any expenses they incur. If either the amendment to the partnership agreement or the merger transaction is not approved, then the two former employees will not receive any commission or fee other than reimbursement for any expenses they incurred in connection with their solicitation of proxies from holders of limited partnership units. Other employees of PDC Securities are full-time employees of PDC and will assist in the solicitation of proxies but will not receive any additional compensation for their solicitation efforts.

In addition to solicitation by use of the mail, directors, officers and employees of PDC may solicit proxies in person or by telephone or other means of communication. The directors, officers and employees will not be additionally compensated, but may be reimbursed for reasonable out-of-pocket expenses incurred in connection with the solicitation.

You may direct any questions or requests for assistance regarding this document and the related proxy materials to PDC at the address above, via e-mail at pdcgas@pdcgas.com, or by telephone at 877-395-3228.

Regardless of the number of limited partnership units you own, your vote is important. Please complete, sign, date and promptly return the accompanying proxy card in the enclosed postage-paid envelope or enter your vote over the internet.

Quorum

PDC and its affiliates will not vote at the special meeting on either of the proposals, either as the managing general partner or with respect to any limited partnership units they own. In addition, their limited partnership units will not be counted in determining a quorum, which requires the presence at the special meeting, in person or represented by proxy, of the holders of a majority of the outstanding limited partnership units held by the investors.

Investor Vote Required to Approve the Amendment to the Partnership Agreement and the Merger Agreement

Approval of each of the amendment to the partnership agreement and the merger agreement requires the affirmative vote of the holders of a majority of the outstanding limited partnership units held by investors as of the close of business on September 1, 2011, the record date for the special meeting of the investors. Limited partnership units owned by PDC or its affiliates will not be considered as outstanding limited partnership units for the purposes of each proposal and may not be voted. The partnership had 1,455.26 limited partnership units outstanding as of the record date, 143.1 (or approximately 9.83%) of which were held of record by PDC or an affiliate thereof. As of the record date, there were 1,031 non-PDC registered holders. Each investor will be entitled to one vote for each limited partnership unit held (or a fractional vote proportional to their interest for interests of less than one limited partnership unit) on all matters to be voted upon at the special meeting.

Abstentions and Broker Non-Votes

Brokers, if any, who hold partnership interests in street name for beneficial owners have the authority to vote on certain “routine” proposals when they have not received instructions from the beneficial owners. However, these brokers are precluded from exercising their voting discretion with respect to the approval and adoption of non-routine matters such as the proposals described in this proxy statement and, thus, absent specific instructions from the beneficial owner of the partnership interests, brokers are not empowered to vote the partnership interests with respect to approving the amendment to the partnership agreement or the merger agreement. These “broker non-votes” will have the effect of a vote against approving the amendment and the merger agreement.

Votes withheld and abstentions are deemed “present” at the special meeting and counted for quorum purposes. Votes withheld and abstentions will have the same effect as a vote against approving the amendment and the merger agreement.

In contrast, the approval of any proposal to adjourn or postpone the special meeting requires that holders of more limited partnership units vote in favor of the proposal to adjourn or postpone the special meeting than vote against the proposal. Accordingly, abstentions and broker non-votes will have no effect on the outcome of such proposal.

Local Laws

Proxy solicitations will not be made to, nor will proxy cards be accepted from, investors in any jurisdiction in which the solicitations would not be in compliance with federal and state securities or other laws.

PROPOSAL 1 — APPROVAL OF THE AMENDMENT TO THE PARTNERSHIP AGREEMENT

The governance of the partnership and the relationship amongst the partners (i.e., PDC and each of the investors) are controlled by the partnership agreement (a copy of which is included as Appendix F to this proxy statement). The partnership agreement provides in Section 11.09 that it may be amended by the consent of the investors owning a majority of the then outstanding limited partnership units entitled to vote.

Consideration of the Amendment Proposal

In order to complete the merger of the partnership with and into the merger sub, the partnership agreement requires an amendment to add a provision expressly permitting the investors to approve the merger. The investors will therefore consider and vote upon a proposed amendment to the partnership agreement granting the express right to investors to consider a merger transaction.

The proposed amendment will add the following sentence to the end of the Section 7.08 in the partnership agreement entitled “Additional Voting Rights”:

“In addition to the preceding voting rights of Investor Partners described in this Section, the affirmative vote of the Investor Partners holding a majority of the then outstanding Units held by the Investor Partners is required for the Partnership to enter into a merger transaction whether or not the Partnership shall be the surviving entity.”

A copy of the form of the proposed amendment to the partnership agreement is included as Appendix G to this proxy statement.

PDC and its affiliates will not vote on this proposal at the special meeting either as managing general partner or with respect to any limited partnership units they own.

The partnership may take action on the above matters at the special meeting, or on any later date to which the special meeting is postponed or adjourned.

THE SPECIAL COMMITTEE, ON BEHALF OF PDC IN ITS CAPACITY AS THE MANAGING GENERAL PARTNER OF THE PARTNERSHIP, RECOMMENDS A VOTE “FOR” THE APPROVAL OF THE AMENDMENT TO THE PARTNERSHIP AGREEMENT.

PROPOSAL 2 — APPROVAL OF THE MERGER AGREEMENT

Proposal 2 will be considered and voted upon only if Proposal 1 is approved by the investors.

Consideration of the Merger Proposal

The investors will consider and vote upon the proposed Agreement and Plan of Merger, dated as of June 20, 2011, by and among the partnership, PDC, and the merger sub, a copy of which is attached as Appendix A to this proxy statement. Pursuant to the merger agreement:


	•	the partnership will merge with and into the merger sub;

	•	as consideration for the merger, the investors will be entitled to receive a cash payment of $4,024 per limited partnership unit, plus the sum of the amounts withheld from per unit cash distributions by the partnership from October 1, 2010 through August 31, 2011 for the partnership’s additional Codell formation development plan, less the sum of the per unit cash distributions made after August 31, 2011 and before the transaction closes, and PDC shall receive additional interests in the merger sub; and

	•	upon completion of the merger, the merger sub shall be the surviving entity, the partnership will cease to exist as a separate business entity, and PDC shall hold all of the interests in the merger sub.

A copy of the merger agreement is included as Appendix A to this proxy statement.

PDC and its affiliates will not vote on this proposal at the special meeting either as managing general partner or with respect to any limited partnership units they own.

The partnership may take action on the above matters at the special meeting, or on any later date to which the special meeting is postponed or adjourned.

THE SPECIAL COMMITTEE, ON BEHALF OF PDC IN ITS CAPACITY AS THE MANAGING GENERAL PARTNER OF THE PARTNERSHIP, RECOMMENDS A VOTE “FOR” THE APPROVAL OF THE MERGER AGREEMENT.

METHOD OF DETERMINING MERGER VALUE
AND AMOUNT OF CASH OFFERED

PDC established the merger value for the partnership for purposes of the merger, and therefore the merger value was not determined by arm’s-length negotiations. See “Risk Factors — You were not independently represented in establishing the terms of the merger,” “Risk Factors — The interests of PDC, the merger sub and their directors and officers may differ from your interests,” and “Special Factors with Respect to the Merger — Conflicting Duties of PDC, Individually and as the General Partner.”

Components of Merger Value

The $4,024 per unit merger value assigned to the partnership was based on an effective transaction date of July 1, 2011 and calculated as follows:


	•	PDC calculated the volumes of the partnership’s proved reserves as of July 1, 2011 based on a future production curve consistent with the production curves used in the partnership’s proved reserve report as of December 31, 2010, with the addition of estimated reserves attributable to non-proven recompletion and drilling projects not included in the partnership’s proved reserve report.

	•	PDC calculated the present value of estimated future net cash flows from the partnership’s estimated production and reserves as of July 1, 2011 using (1) 100% of the arithmetic average of the five-year NYMEX futures price as of March 31, 2011 for oil, which was approximately $104.29 per barrel, less standard industry adjustments and differentials by area, and (2) 100% of the arithmetic average of the five-year NYMEX futures price as of March 31, 2011 for gas, which was approximately $5.37 per Mcf, less standard industry adjustments and differentials by area. Standard industry adjustments included:


	•	the effects of oil quality;

	•	BTU content for gas;

	•	oil and gas gathering and transportation costs; and

	•	gas processing costs and shrinkage.

Those adjustments reflected assumptions about the costs to extract and process, if necessary, crude oil, natural gas liquids and natural gas and transport them to their point of sale.


	•	PDC calculated the present value of the estimated future net cash flows using before tax discount rates of 15% for proved developed producing reserves and 25% for proved developed non-producing reserves.


	•	Proved developed non-producing reserves include both Codell refracturing and Niobrara recompletion projects.


	•	Substantial capital expenditures could increase production, but given that the partnership cannot incur debt, such capital expenditures could only be made by withholding distributions over the long term.

	•	Non-proven undeveloped projects were valued at $10,000 per drilling location.

A copy of the partnership’s reserve report as of December 31, 2010, including the assumptions used in the preparation of that report, is included as Appendix D to this proxy statement. The partnership’s financial statements as of June 30, 2011 and 2010 and for the three and six month periods then ended and as of December 31, 2010 and 2009 and for the years then ended are included as Appendix E to this proxy statement.

From the mailing date of this document to the closing date of the merger, PDC will not adjust any of the components of the merger value.

Estimated Reserve Volumes. PDC believes it is appropriate to calculate estimated reserve volumes as of July 1, 2011 based upon data rolled forward from the partnership’s 2010 year-end reserve report, because PDC anticipates that the merger will be consummated in 2011. In addition, because the partnership’s properties are long-lived, mature, producing properties, PDC believes that the production curves used in preparing the partnership’s reserve report as of December 31, 2010, plus the addition of estimated reserves attributable to recompletion and drilling projects not in the proved reserve report, are appropriate and reasonable.

The reserve estimates do not reflect the effect of any “take-or-pay” clauses in gas contracts, which effect PDC expects to be insignificant.

Present Value of Estimated Future Net Cash Flows. PDC calculated the present value of estimated future net cash flows of the partnership’s estimated reserves as of March 31, 2011. In determining the present value (and in order to give effect to the inherent uncertainties associated with the timing and profitability of extracting non-producing reserves), PDC used the prices described in the second bullet point under “— Components of Merger Value” above, and used production costs consistent with those assumed in the partnership’s 2010 year-end reserve report. PDC believes it is appropriate to use production costs similar to those assumed in the 2010 year-end reserve report because such costs have been fairly stable and predictable over the last several years. In addition, PDC used discount rates of 15% for proved developed producing reserves and 25% for proved developed non-producing reserves to determine the present value of estimated future net cash flows from the partnership’s reserves. PDC believes that these discount rates are within the range of discount rates commonly used in the oil and gas industry in property acquisitions of producing properties, although they are higher than the 10% rate that the SEC requires for comparative purposes in the year-end reports of publicly traded oil and gas companies. Undeveloped reserves were valued at $10,000 per drilling location because these wells are infill projects to 20 acres, require significant capital, and are scheduled for implementation more than five years in the future.

PDC does not believe that the present value of the partnership’s proved reserves is significantly affected by curtailments of gas production.

Minimum Merger Value. PDC determined that the merger value should be equal to or greater than 4.5 times the estimated aggregate distributions per limited partnership unit for the twelve months ended March 31, 2011. If the sum of the components above did not equal or exceed 4.5 times the estimated aggregate distributions per limited partnership unit for the twelve months ended March 31, 2011, an adjustment was made to achieve this value.

Effective Date. A regular cash distribution will be made by the partnership in August 2011 based on the partnership’s production through June 2011. The merger value was determined based on data projected as of July 1, 2011. Accordingly, if approved by the investors and completed, investors will be entitled to receive cash in an amount equal to $4,024 per limited partnership unit, plus the sum of the amounts withheld from per unit cash distributions by the partnership from October 1, 2010 through August 31, 2011 for the partnership’s additional Codell formation development plan, less the sum of the per unit cash distributions made after August 31, 2011.

Other Methods of Determining Merger Value

PDC and the special committee believe that the method used to determine the merger value is a fair and reasonable method of valuing the partnership’s properties. However, the method selected might not accurately reflect the value of the partnership’s assets. See “Risk Factors — The estimates of proved reserves and future net revenues considered when calculating the merger value, and underlying assumptions about future production, commodity prices and costs, may be incorrect,” “Risk Factors — The merger value might not reflect the value of the partnership’s assets” and “Risk Factors — PDC does not expect that the merger value will be adjusted for changes before the completion of the merger.” PDC considered a number of alternative methods of determining the merger

value before selecting a method. The following alternative methods for determining the merger value should be taken into account in assessing the adequacy of the method used by PDC:

Book Value of Assets. PDC did not base the calculation of merger value on the net book value of the partnership’s assets. The net book value of the partnership’s assets is based upon the financial statements reported in accordance with generally accepted accounting principles. The net book value is not adjusted for changes in the fair market value of the assets. For this reason, PDC and the merger sub believe that the merger value is more indicative of the fair market value of the assets of the partnership than the assets’ net book value.

Trading Price of Units. The partnership’s limited partnership units are not traded on a national stock exchange or in any other significant market. Although some limited partnership units are occasionally sold in private or over-the-counter transactions, PDC believes any market for the partnership interests is highly illiquid and reflects an illiquidity discount, and is therefore not reliable as an indicator of value. As a result, PDC did not base the calculation of merger value on recent trading prices of the partnership’s limited partnership units.

THE MERGER AGREEMENT

The following describes the material terms of the merger agreement among the partnership, PDC and the merger sub. The full text of the merger agreement is included as Appendix A to this proxy statement and is incorporated herein by reference. We encourage you to read the entire merger agreement.

Structure; Effective Time

The merger agreement provides for the merger of the partnership with and into the merger sub, with the merger sub surviving the merger. The merger will become effective at the time of the filing of certificates of merger with the Secretary of State of the State of West Virginia and the Secretary of State of the State of Delaware. The certificates of merger are expected to be filed as soon as practicable after the last condition precedent to the merger set forth in the merger agreement has been satisfied or waived. We estimate that the closing of the merger will be in the fourth quarter of 2011.

Representations and Warranties of PDC, the Merger Sub and the Partnership

The merger agreement contains substantially reciprocal representations and warranties of PDC and the merger sub, on the one hand, and the partnership, on the other hand, including with respect to the following matters:


	•	due formation, good standing, and corporate, limited liability company or partnership power and authority;

	•	authority to enter into, and the validity and enforceability of, the merger agreement; and

	•	the absence of contracts or agreements having terms that would be violated by the execution and delivery of the merger agreement or the consummation of the merger.

Payment of Consideration for the Investor Limited Partnership Units

Upon completion of the merger, the investors will be entitled to receive a cash payment of $4,024 per limited partnership unit, plus the sum of the amounts withheld from per unit cash distributions by the partnership from October 1, 2010 through August 31, 2011 for the partnership’s additional Codell formation development plan, less the sum of the per unit cash distributions made after August 31, 2011 and before the transaction closes, for their limited partnership units (which shall be proportionally adjusted for partial limited partnership units). The per unit merger amount offered to investors under the merger agreement was determined using an effective transaction date of July 1, 2011 and includes adjustments, if applicable, to account for certain increases in commodity prices between the date of entering into the merger agreement and the date of the definitive proxy statement.

Conditions to Complete the Merger

The obligation of the parties to complete the merger is subject to the satisfaction or waiver, subject to compliance with applicable law, of certain conditions, including:


	•	the approval of the amendment to the partnership agreement and the merger agreement by the holders of at least a majority of the outstanding limited partnership units held by the investors;

	•	the absence of any law, rule, regulation, judgment, injunction, order or decree that would make the merger illegal or prohibit the consummation of the merger;

	•	the absence of any filed or pending suit, action or proceeding challenging the legality or any aspect of the merger or the transactions related to the merger; and

	•	the receipt of all approvals, authorizations and consents of third parties, including regulatory authorities, required for consummation of the merger.

In addition, the obligation of the partnership to complete the merger is further subject to the conditions that the representations and warranties of PDC and the merger sub shall be true and correct and that PDC and the merger sub shall have performed in all material respects all of their obligations under the merger agreement, and the obligation of PDC and the merger sub to complete the merger is further subject to the condition that no event, circumstance,

condition, development or occurrence causing, resulting in or having, or reasonably expected to cause, result in or have, a material adverse effect on the partnership’s business, operations, properties (in all cases taken as a whole), condition (financial or otherwise), results of operations, assets (in all cases taken as a whole), liabilities or cash flows.

The parties may not waive the requirement that the amendment to the partnership agreement and the merger agreement be approved by a majority of the outstanding limited partnership units held by the investors. If the holders of a majority of the outstanding limited partnership units held by investors approve the amendment to the partnership agreement and the merger agreement, the parties may choose to complete the merger even though a condition has not been satisfied, so long as the law allows them to do so.

Termination of the Merger and the Merger Agreement

The merger agreement may be terminated and the merger abandoned, in whole or in part, at any time prior to the effective time:


	•	by the mutual written consent of all parties to the merger agreement (with the special committee required to approve any matter for the partnership);

	•	by any party to the merger agreement (with the special committee required to approve any matter for the partnership), if:


	•	closing has not occurred by December 15, 2011;

	•	any applicable law, rule or regulation makes consummation of the merger illegal or otherwise prohibited, or any final and non-appealable judgment, injunction, order or decree enjoining any party from consummating the merger is entered; or

	•	any suit, action or proceeding is filed or pending against PDC, the merger sub or any officer, director, manager, member or affiliate of PDC or the merger sub challenging the legality or any aspect of the merger or the transactions related thereto;


	•	by the partnership (with the special committee required to approve any matter for the partnership), if PDC or the merger sub has failed to perform its obligations under the merger agreement, and such failure has a material adverse effect on PDC or the merger sub, or materially and adversely affects the transactions contemplated by the merger agreement, and is either incapable of being cured or is not cured within 30 days of notice thereof from the special committee;

	•	by PDC, if the partnership has failed to perform its obligations under the merger agreement, and such failure has a material adverse effect on the partnership, or materially and adversely affects the transactions contemplated by the merger agreement, and is either incapable of being cured or is not cured by the partnership within 30 days following written notice thereof from PDC; or

	•	by the special committee on behalf of the partnership if, prior to obtaining the required vote of the investors, the partnership (A) has materially complied with its obligations under the merger agreement and (B) has entered into a definitive acquisition agreement providing for a “superior proposal” (as defined below); provided that the partnership may not enter into any such definitive acquisition agreement or terminate the merger agreement pursuant to this provision until at least five days have passed after the special committee informs PDC of its intention to accept a superior proposal (during which time PDC may respond to any superior proposal). As used in the merger agreement, “superior proposal” means a bona fide written offer, obtained after the date of the merger agreement and not in breach of the merger agreement, made by a third party to the special committee to acquire, directly or indirectly, for consideration consisting of cash, all of the investors’ interests in the partnership (i) which is not subject to a financing contingency, (ii) which is otherwise on terms and conditions which the special committee determines in its good faith judgment (after consultation with outside counsel and a financial advisor of national reputation) to be more favorable to the investors from a financial point of view than the merger and the merger agreement and the other transactions contemplated thereby, and (iii) which is reasonably capable of being completed, taking into account any approval requirements and all financial, legal, operational, regulatory and other aspects of such proposal.

If the merger agreement is validly terminated or the merger is abandoned, no party shall have any liabilities or obligations to the other parties except:


	•	PDC will pay all expenses and fees related to the merger incurred before the termination of the merger agreement or abandonment of the merger; and

	•	a party will be liable if that party is in breach of the merger agreement.

Amending the Merger Agreement

The parties may amend or cancel the merger agreement prior to the effective date by action taken or authorized by their respective boards of directors, members or managing general partner (through the special committee), as appropriate. The merger agreement may be amended, supplemented or modified only by written agreement among PDC, the merger sub and the partnership.

Waiving Certain Merger Provisions

Prior to the effective time, the parties may:


	•	extend the time for the performance of any of the obligations of the parties;

	•	waive any inaccuracies in the representations and warranties in the merger agreement or in a document delivered pursuant to the merger agreement; and

	•	waive compliance with any agreement or condition in the merger agreement (other than the requirement that the amendment to the partnership agreement and the merger agreement be approved by a majority of the outstanding limited partnership units held by the investors).

Any such extension or waiver will be valid only if it is in writing and signed by the party against whom the extension or waiver is to be effective.

THIRD-PARTY OFFERS

The special committee will consider offers from third parties to purchase the partnership or its assets. Those who wish to make an offer for the partnership or its assets must demonstrate to the special committee’s reasonable satisfaction their financial ability and willingness to complete such a transaction. Before reviewing non-public information about the partnership, a third party will need to enter into a customary confidentiality agreement. Offers should be at prices and on terms that are fair to the investors and more favorable to the investors than the prices and terms proposed for the merger in this document. PDC reserves the right to match or top any such offer. Persons desiring to make an offer for the partnership should contact Lance Lauck, Senior Vice President Business Development, at 303-860-5800.

DISTRIBUTION OF CASH PAYMENTS

Upon completion of the merger, the investors will have no continuing interest in, or rights as partners of, the partnership. The transfer books of the partnership will be closed on the closing date of the merger. All limited partnership units in the partnership will cease to be outstanding, will automatically be cancelled and retired, and will cease to exist.

PDC intends to pay the merger value to the investors of record by mailing checks within 30 days following the effectiveness of the merger. Checks will be mailed to the same addresses to which monthly distribution checks are mailed.

RIGHTS OF DISSENTING INVESTORS

You will be bound by the merger if the investors vote a majority of their limited partnership units in favor of the merger, even if you vote against the merger. Nevertheless, pursuant to Section 7.08 of the partnership agreement, an investor is entitled to exercise the same rights as a dissenting shareholder under Article 13 of the West Virginia Business Corporation Act (the “Act”) to object to the merger agreement and demand that the merger sub, as the surviving entity, pay the fair value of his limited partnership units as determined in accordance with the West Virginia statutory provisions. The Act defines “fair value” as the value of a corporation’s shares determined immediately before the effectuation of the corporate action to which the dissenter objects, using customary and current valuation concepts and techniques generally employed for similar businesses in the context of the transaction requiring appraisal and without discounting for lack of marketability.

The following summarizes the material provisions of West Virginia law relating to appraisal rights and is qualified in its entirety by reference to the applicable statutory provisions, which are set forth in full in Appendix C to this document.

The investors must follow certain prescribed procedures in their exercise of appraisal rights. The failure to follow these procedures precisely, on a timely basis and in the manner required by Article 13 of the Act, may result in a loss of appraisal rights.

1. To be entitled to payment of fair value as a dissenting investor, an investor must (i) before the vote to approve the merger is taken, deliver to PDC, the managing general partner of the partnership, written notice of the investor’s intent to demand payment, (ii) not vote in favor of the proposed merger agreement, and (iii) make a payment demand, in each case as provided below.

2. Any investor electing to assert appraisal rights must deliver to PDC, prior to the taking of the vote at the special meeting to be held on October 28, 2011, written notice of the investor’s intent to demand payment for such investor’s limited partnership units if the proposed merger is effectuated. Additionally, such investor cannot vote in favor of the proposed merger agreement. If the investor does not comply with these two requirements, the investor will not be entitled to payment for the investor’s limited partnership units under Article 13 of the Act. The mere filing of a proxy directing a vote against the merger agreement, or a purported objection to the merger submitted on a proxy, does not constitute written notice of an investor’s intent to demand payment for such investor’s limited partnership units.

3. If the proposed merger becomes effective, the merger sub will send a written appraisal notice to all dissenting investors no later than ten (10) days after the merger becomes effective. The appraisal notice must be accompanied by a copy of Article 13 of the Act and a form (the “Certification Form”) that specifies the date of the first announcement to the investors of the principal terms of the proposed merger (the “Announcement Date”) and which requires the investor asserting appraisal rights to certify whether or not beneficial ownership of those limited partnership units for which appraisal rights are asserted was acquired before that date, and that the investor did not vote for the transaction. The appraisal notice must also state: (i) where the Certification Form must be sent; (ii) the date by which the merger sub must receive the Certification Form (the “Due Date”), which may not be fewer than forty nor more than sixty days after the date the appraisal notice and Certification Form are sent, and state that the investor will be deemed to have waived the right to demand appraisal with respect to the limited partnership units unless the Certification Form is received by the merger sub by the Due Date; (iii) the merger sub’s estimate of the fair value of the limited partnership units; (iv) that, if requested in writing, the merger sub will provide to the investor so requesting, within ten days after the Due Date, the number of investors who returned the Certification Forms by the Due Date and the total number of limited partnership units owned by them; and (v) the date by which an investor’s notice to withdraw his or her election to exercise appraisal rights must be received by the merger sub, which we refer to as the “Withdrawal Date,” which date must be within twenty days after the Due Date.

4. The merger sub will pay in cash to the investors who have completed and returned the Certification Form as provided herein an amount estimated by the merger sub to be the fair value of the investor’s limited partnership units, plus interest as determined in accordance with the Act, within 30 days of the Due Date. The payment must be accompanied by: (i) the partnership’s balance sheet as of the end of a fiscal year ending not more than sixteen (16) months before the date of payment, an income statement for that year, a statement of changes in partners’

equity for that year and the latest available interim financial statements, if any; (ii) a statement of the merger sub’s estimate of the fair value of the limited partnership units; and (iii) a statement that the investor has a right to timely demand further payment under Section 1326 of the Act. Failure to timely demand further payment shall be deemed acceptance of the payment delivered as payment in full for the investor’s limited partnership units.

5. If an investor fails to certify on the Certification Form that the investor, or the beneficial owner of the investor’s limited partnership units, acquired the limited partnership units for which appraisal rights are asserted before the Announcement Date, the merger sub may elect to treat such limited partnership units as “after-acquired limited partnership units” and may withhold payment. If the merger sub elects to withhold payment, the Act provides that the merger sub must, within 30 days of the Due Date, notify all investors described in this paragraph: (i) of the partnership’s balance sheet as of the end of a fiscal year ending not more than sixteen (16) months before the date of payment, an income statement for that year, a statement of changes in partners’ equity for that year and the latest available interim financial statements, if any; (ii) of the merger sub’s estimate of the fair value of the limited partnership units; (iii) that such investors may accept such estimate of fair value, plus interest, in full satisfaction of their demands or that they may demand an appraisal under Section 1326 of the Act; (iv) that the investors who wish to accept the merger sub’s offer must notify the merger sub within 30 days after receiving the offer; and (v) that those investors who do not satisfy the requirements for demanding appraisal under Section 1326 of the Act will be deemed to have accepted the offer.

6. If an investor who has received a payment as described in paragraph 4 above is dissatisfied with the payment, the investor must notify the merger sub in writing of his estimate of the fair value of the limited partnership units and demand payment of that estimate plus interest and less any payment due pursuant to Section 1324 of the Act. If an investor holding “after acquired limited partnership units” as described in paragraph 5 above is dissatisfied with the payment offered to him, the investor must reject the offer and demand payment of his stated estimate of the fair value of the limited partnership units plus interest. An investor who fails to notify the merger sub in writing of his demand to be paid his stated estimate of the fair value plus interest as provided in this paragraph within 30 days after receiving the merger sub’s payment (or in the case of after acquired limited partnership units, offer of payment) waives the right to demand payment pursuant to this paragraph and Section 1326 of the Act, and is entitled only to the payment the merger sub has made (or in the case of after acquired limited partnership units, offered).

7. An investor who returned the Certification Form in the time period and in the manner described in paragraph 3 above may decline to exercise appraisal rights and withdraw from the appraisal process by sending a written notice of such withdrawal to the merger sub on or before the Withdrawal Date. In the event an investor fails to send a notice of withdrawal by the Withdrawal Date, the investor may only so withdraw with the merger sub’s written consent.

8. If a dissenting investor’s demand for payment remains unsettled, the Act requires the merger sub to commence a proceeding within sixty days after receiving the payment demand and to petition the court to determine the fair value of the limited partnership units and accrued interest. If the merger sub does not commence the proceeding within the sixty day period, it must pay each dissenting investor whose demand remains unsettled the amount demanded by each such dissenting investor, plus interest, in cash. The merger sub must make all dissenting investors, whether or not residents of West Virginia, whose demands remain unsettled parties to the proceeding as in an action against their limited partnership units, and serve all such dissenting investors with a copy of the petition. Nonresidents may be served by certified mail or by publication as provided by law. The jurisdiction of the court in which the proceeding is commenced is plenary and exclusive and there is no right to trial by jury.

The court in an appraisal proceeding will determine all costs of the proceeding and assess those costs against the merger sub, except that the court may assess costs against some or all of the dissenting investors to the extent that the court finds that such dissenting investors acted arbitrarily, vexatiously or not in good faith in demanding payment. The court may also assess the fees and expenses of counsel and experts for the respective parties in amounts the court finds equitable to the extent set forth in Section 1331 of the Act. If the court determines that the services of counsel for any dissenting investor were of substantial benefit to other dissenting investors similarly situated, that court may award to these attorneys reasonable fees to be paid out of the amounts awarded to the dissenting investors who benefited. If the merger sub fails to make a required payment pursuant to Section 1324,

1325 or 1326 of the Act (as described in the paragraphs 4, 5 and 6 above), the investor may sue for the amount owed and, to the extent successful, is entitled to recover from the merger sub all costs and expenses of the suit, including counsel fees.

Investors considering seeking appraisal of their limited partnership units by exercising their appraisal rights should be aware that the fair value of their limited partnership units determined under West Virginia law could be more than, the same as, or less than the merger consideration that they are entitled to receive under the merger agreement if they do not seek appraisal of their limited partnership units.

The foregoing discussion does not purport to be a complete statement of the procedures to be followed by investors desiring to exercise their appraisal rights. Because exercise of those rights requires strict adherence to the relevant provisions of the West Virginia Business Corporation Act, each investor who may desire to exercise appraisal rights is advised individually to consult the law (as set forth in Appendix C to this document) and to comply with the provisions of the statute.

Investors wishing to exercise appraisal rights are advised to consult their own counsel to ensure that they fully and properly comply with the requirements of West Virginia law.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The partnership does not have any directors or executive officers. The managing general partner of the partnership, PDC, has the exclusive right and full authority to manage, control and administer the partnership’s business. Under the partnership agreement, limited partners holding a majority of the outstanding limited partnership interests have the right to take certain actions, including the removal of the managing general partner or any other general partner. PDC is not aware of any current arrangement or activity that may lead to such removal. The merger sub and the officers and directors of PDC do not have any direct financial or equity interests in the partnership and own no limited partnership units. In addition, PDC is not aware of any person who beneficially owns five percent (5%) or more of the outstanding limited partnership units of the partnership.

The following table presents information as of September 7, 2011 concerning PDC’s interest in the partnership. Each partner exercises sole voting and investing power with respect to the interest beneficially owned.

Limited Partnership Units

Number

of Units

Outstanding

Percentage

Which

of Total

Represent

Number

Partnership

80% of Total

of Units

Percentage

Interests

Partnership

Beneficially

of Total Units

Beneficially

Interests⁽¹⁾

Owned

Outstanding

Owned

Person or Group

1,455.26

Petroleum Development Corporation^(2)(3)(4)

—

143.1

9.83

7.87

Investors beneficially owning 5% or more of limited partner interests

—


(1)		Additional general partner units were converted to limited partner interests at the completion of drilling activities.

(2)		Petroleum Development Corporation, 1775 Sherman Street Suite 3000, Denver, Colorado 80203.

(3)		No director or officer of PDC owns interest in PDC limited partnerships. Pursuant to the partnership agreement individual investor partners may present their units to PDC for purchase subject to certain conditions; however, PDC is not obligated to purchase more than 10% of the total outstanding units during any calendar year.

(4)		In addition to this ownership percentage of limited partnership interest, Petroleum Development Corporation owns a Managing General Partner interest of 20%.

TRANSACTIONS AMONG THE PARTNERSHIP, PDC,
THE MERGER SUB AND THEIR DIRECTORS AND OFFICERS

Except as described in this document, there have not been any contacts, transactions or negotiations between PDC, the merger sub, any of their respective subsidiaries, or, to the knowledge of PDC and the merger sub, any director, manager or executive officer of PDC or the merger sub, on the one hand, and the partnership or its directors, officers or affiliates, on the other hand, that are required to be disclosed pursuant to the rules and regulations of the SEC. Except as described in this document, none of PDC, the merger sub, or, to the knowledge of PDC and the merger sub, any director or executive officer of PDC or the merger sub, has any contract, arrangement, understanding or relationship with any person with respect to any securities of the partnership.

If you approve the merger, there are various ways that the merger sub may use the properties. The merger sub may continue to operate the properties, it may sell the properties to third parties or it may distribute the properties to its sole member, PDC. Although the merger sub plans to operate the properties in the immediate future following completion of the merger, it has not decided how to use the properties in the long-term.

Certain Relationships and Related Transactions

PDC transacts all of the partnership’s business on behalf of the partnership. Under the Drilling and Operating Agreement of the partnership, or the D&O Agreement, PDC provides all necessary labor, vehicles, supervision, management, accounting, and overhead services for normal production operations, and may deduct from partnership revenues a fixed monthly charge for these services. The charge for these operations and field supervision fees, which we refer to as well tending fees, for each producing well is based on competitive industry field rates which vary based on areas of operation. The well tending fees and administration fees may be adjusted annually to an amount equal to the rates initially established by the D&O Agreement multiplied by the then current average of the Oil and Gas Extraction Index and the Professional and Technical Services Index, 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. This average is commonly referred to as the Accounting Procedure Wage Index Adjustment which is published annually by the Council of Petroleum Accountants Societies, or COPAS. These rates are reflective of similar costs incurred by comparable operators in the production field. PDC, in certain circumstances, has and may in the future, provide equipment or supplies, perform salt water disposal services or other services for the partnership at the lesser of cost or competitive prices in the area of operations.

Industry specialists, employed by PDC to support the partnership’s business operations include the following:


	•	Geoscientists who identify and develop PDC’s drilling prospects and oversee the drilling process;

	•	Petroleum engineers who plan and direct PDC’s well completions and recompletions, construct and operate PDC’s well and gathering lines, and manage PDC’s production operations;

	•	Petroleum reserve engineers who evaluate well reserves at least annually and monitor individual well performance against expectations; and

	•	Full-time well tenders and supervisors who operate PDC wells.

Salary and employment benefit costs for the above specialized services are covered by the monthly fees paid to PDC, as managing general partner of the partnership.

PDC procures services on behalf of the partnership for costs and expenses related to the purchase or repairs of equipment, materials, third-party services, brine disposal and the rebuilding of access roads. These are charged at the invoice cost of the materials purchased or the third-party services performed. In addition to the industry specialists above who provide technical management, PDC may provide services, at competitive rates, from PDC-owned service rigs, a water truck, steel tanks used temporarily on the well location during the drilling and completion of a well, roustabouts and other assorted small equipment and services. A roustabout is a natural gas and oil field employee who provides skilled general labor for assembling well components and other similar tasks. PDC may lay short gathering lines, or may subcontract all or part of the work where it is more cost effective for the partnership.

PDC transacts business on behalf of the partnership under the authority of the D&O Agreement. Revenues and other cash inflows received on behalf of the partnership are distributed to the investors net of (after deducting) corresponding operating costs and other cash outflows incurred on behalf of the partnership. The fair value of the partnership’s portion of unexpired derivative instruments is recorded on the balance sheets under the captions “Due from Managing General Partner — derivatives” in the case of net unrealized gains or “Due to Managing General Partner — derivatives” in the case of net unrealized losses.

The following table presents transactions with PDC reflected in the balance sheet line item “Due from Managing General Partner-other, net” which remain undistributed or unsettled with the investors as of the dates indicated. This data has been derived from the partnership’s audited financial statements as of December 31, 2010 and 2009 and for the years then ended and unaudited financial statements as of June 30, 2011 and 2010 and for the periods then ended, which are included as Appendix E to this proxy statement.


	June 30,			December 31,			December 31,
	2011			2010			2009

Natural gas, NGLs and crude oil sales revenues collected from the partnership’s third-party customers	$	104,264		$	83,892		$	175,272
Commodity price risk management, realized gains		9,509			48,073			155,373
Other(1)		(444,655	)		(719,695	)		(276,270	)

Total due (to) from Managing General Partner-other, net	$	(330,882	)	$	(587,730	)	$	54,375


(1)		All other unsettled transactions, excluding derivative instruments, between the partnership and PDC. Except as noted below, the majority of these are operating costs or general and administrative costs which have not been deducted from distributions.

As of December 31, 2008, certain amounts recorded by the partnership as assets in the account “Due from Managing General Partner — other, net” included amounts that were being held as restricted cash by PDC, on behalf of the partnership for the over-withholding of production taxes related to partnership production prior to 2007, including accrued interest thereon. During September 2009, the partnership collected these amounts totaling $1.0 million, from PDC.

Additionally, certain amounts representing royalties on partnership production paid in September 2009 were recorded by the partnership as liabilities in the account “Due from Managing General Partner-other, net.” These amounts, which totaled approximately $232,000 including legal fees of approximately $20,000, represented the partnership’s share of the court approved royalty litigation payment and settlement. During September 2009, all settlement costs related to this litigation were paid by the partnership to PDC.

Commencing with the 36th month of well operations, PDC started withholding from monthly partnership distributable cash, amounts to be used to fund statutorily-mandated well plugging, abandonment and environmental site restoration expenditures. A partnership well may be sold or plugged, reclaimed and abandoned, with consent of all non-operators, when depleted or an evaluation is made that the well has become uneconomical to produce. Per-well plugging fees withheld during 2010 and 2009 were $50 per well each month the well produced. The total amount withheld from partnership distributable cash for the purposes of funding future partnership obligations, is recorded on the balance sheets in the long-term asset line captioned, “Other Assets.”

The following table presents partnership transactions, excluding derivative transactions, with PDC and its affiliates for the three and six months ended June 30, 2011 and 2010 and the years ended December 31, 2010 and 2009. This data has been derived from the partnership’s audited financial statements as of December 31, 2010 and 2009 and for the years then ended and unaudited financial statements as of June 30, 2011 and 2010 and for the periods then ended, which are included as Appendix E to this proxy statement. “Well operations and maintenance”

and “Gathering, compression and processing fees” are included in the “Natural gas, NGLs and crude oil production costs” line item on the statements of operations.


	Three Months Ended				Six Months Ended				Year Ended
	June 30,				June 30,				December 31,
	2011		2010		2011		2010		2010		2009

Well operations and maintenance⁽¹⁾	$	94,617	$	296,167	$	219,577	$	675,540	$	996,079	$	547,923
Gathering, compression and processing fees⁽²⁾		11,018		11,415		21,763		23,501		46,992		44,787
Direct costs — general and administrative⁽³⁾		40,013		4,917		235,970		6,915		474,479		35,465
Cash distributions⁽⁴⁾⁽⁵⁾		3,776		26,973		7,637		116,669		115,301		531,402


(1)		Under the D&O Agreement, PDC, as operator of the wells, receives payments for well charges and lease operating supplies and maintenance expenses from the partnership when the wells begin producing.

		Well charges. PDC receives reimbursement at actual cost for all direct expenses incurred on behalf of the partnership, monthly well operating charges for operating and maintaining the wells during producing operations, which reflects a competitive field rate, and a monthly administration charge for partnership activities.

		Under the D&O Agreement, PDC provides all necessary labor, vehicles, supervision, management, accounting, and overhead services for normal production operations, and may deduct from partnership revenues a fixed monthly charge for these services. The charge for these operations and field supervision fees (referred to as “well tending fees”) for each producing well is based on competitive industry field rates which vary based on areas of operation. The well tending fees and administration fees may be adjusted annually to an amount equal to the rates initially established by the Drilling and Operating Agreement multiplied by the then current average of the Oil and Gas Extraction Index and the Professional and Technical Services Index, 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. This average is commonly referred to as the Accounting Procedure Wage Index Adjustment which is published annually by COPAS. These rates are reflective of similar costs incurred by comparable operators in the production field. PDC, in certain circumstances, has and may in the future, provided equipment or supplies, performed salt water disposal services and other services for the partnership at the lesser of cost or competitive prices in the area of operations.

		PDC as operator bills non-routine operations and administration costs to the partnership at its cost. PDC may not benefit by inter-positioning itself between the partnership and the actual provider of operator services. In no event is any consideration received for operator services duplicative of any consideration or reimbursement received under the partnership agreement.

		The well operating, or well tending, charges cover all normal and regularly recurring operating expenses for the production, delivery and sale of natural gas, NGLs and crude oil, such as:


	•	well tending, routine maintenance and adjustment;

	•	reading meters, recording production, pumping, maintaining appropriate books and records; and

	•	preparing production related reports to the partnership and government agencies.

The well supervision fees do not include costs and expenses related to:


	•	the purchase or repairs of equipment, materials or third-party services;

	•	the cost of compression and third-party gathering services, or gathering costs;

	•	brine disposal; and

	•	rebuilding of access roads.


		These costs are charged at the invoice cost of the materials purchased or the third-party services performed.


		Lease Operating Supplies and Maintenance Expense. PDC and its affiliates may enter into other transactions with the partnership for services, supplies and equipment during the production phase of the partnership, and is entitled to compensation at competitive prices and terms as determined by reference to charges of unaffiliated companies providing similar services, supplies and equipment. Management believes these transactions were on terms no less favorable than could have been obtained from non-affiliated third parties.

(2)		Under the partnership agreement, PDC is responsible for gathering, compression, processing and transporting the natural gas produced by the partnership to interstate pipeline systems, local distribution companies, and/or end-users in the area from the point the natural gas from the well is commingled with natural gas from other wells. In such a case, PDC, as managing general partner, uses gathering systems already owned by PDC, or PDC constructs the necessary facilities if no such line exists. In such a case, the partnership pays a gathering, compression and processing fee directly to PDC at competitive rates. If a third-party gathering system is used, the partnership pays the gathering fee charged by the third-party gathering the natural gas.

(3)		PDC is reimbursed by the partnership for all direct costs expended by it on the partnership’s behalf for administrative and professional fees, such as legal expenses, audit fees and engineering fees for reserve reports.

(4)		Except as modified under the Standard Performance Obligation, the partnership agreement provides for the allocation of cash distributions 80% to partnership investors and 20% to PDC, as managing general partner of the partnership. Cash distributions to PDC for the three and six months ended June 30, 2011 were reduced by $1,922 and $3,959, respectively, $22,802 and $65,296 for the three and six months ended June 30, 2010 and for the years ended 2010 and 2009 were reduced by $76,686 and $115,058, respectively, due to Preferred Cash Distributions made by PDC to the investors under the Performance Standard Obligation provision of the partnership agreement. Cash distributions to investors include $1,744 and $3,532 during the three and six months ended June 30, 2011 and 2010, respectively, $15,135 and $54,072 during the three and six months ended June 30, 2010, respectively, and $57,604 and $180,345 during the years ended 2010 and 2009, respectively, for limited partnership units repurchased by PDC.

(5)		Distributions to partners of the partnership in 2009 were impacted by several non-recurring items.

Transactions in Limited Partnership Units

There have been no transactions (including repurchases) in limited partnership units during the past 60 days by PDC, any of PDC’s officers or directors, any of the merger sub’s officers, or any associate or majority-owned subsidiary of the foregoing.

None of PDC’s current officers or directors have made purchases of limited partnership units during the past two years. The following table shows purchases of limited partnership units during the past two years effected by PDC:


	Total Number of
	Limited Partner		Range of Prices				Weighted Average
Quarter	Units Purchased		Paid per Unit				Price Paid per Unit

Third Quarter 2011⁽¹⁾		—	$	—	$	—	$	—
Second Quarter 2011		0.75		660		660		660
First Quarter 2011		4.00		940		1,980		1,379
Fourth Quarter 2010		1.25		1,840		1,940		1,920
Third Quarter 2010		0.50		2,200		2,200		2,200
Second Quarter 2010		0.25		2,360		2,360		2,360
First Quarter 2010		—		—		—		—
Fourth Quarter 2009		—		—		—		—
Third Quarter 2009		6.25		4,376		4,552		4,411
Second Quarter 2009		1.40		4,640		4,775		4,679
First Quarter 2009		3.50		4,590		4,880		4,796
Fourth Quarter 2008		0.25		4,760		4,760		4,760
Third Quarter 2008		0.40		4,050		4,050		4,050
Second Quarter 2008		1.50		3,040		3,104		3,093


(1)		Through September 7, 2011.

MANAGEMENT

PDC

The executive officers and directors of PDC, their principal occupations for the past five years and additional information is set forth below:


			Positions and	Director		Directorship
Name	Age		Offices Held	Since		Term Expires

James M. Trimble		63	Chief Executive Officer, President and Director		2009		2013
Gysle R. Shellum		59	Chief Financial Officer		—		—
R. Scott Meyers		37	Chief Accounting Officer		—		—
Barton R. Brookman, Jr.		49	Senior Vice President Exploration and Production		—		—
Daniel W. Amidon		51	General Counsel and Secretary		—		—
Lance Lauck		48	Senior Vice President Business Development		—		—
Jeffrey C. Swoveland		56	Director and Chairman		1991		2014
Joseph E. Casabona		67	Director		2007		2014
Anthony J. Crisafio		58	Director		2006		2012
Larry F. Mazza		50	Director		2007		2013
David C. Parke		44	Director		2003		2014
Kimberly Luff Wakim		53	Director		2003		2012

James M. Trimble was appointed as the Chief Executive Officer and President of PDC in June 2011. Mr. Trimble retired in November 2010 as Managing Director of Grand Gulf Energy, Limited (ASX: GGE), a public company traded on the Australian Securities Exchange, a position he had held since August 2005. He remains a member of the board of Directors of Grand Gulf Energy, Limited. In January 2005, Mr. Trimble founded and served until November 2010 as President and Chief Executive Officer of the U.S. subsidiary Grand Gulf Energy Company LLC, an exploration and development company focused primarily on drilling in mature basins in Texas, Louisiana and Oklahoma. From 2000 through 2004, Mr. Trimble was Chief Executive Officer of Elysium Energy and then Tex-Cal Energy LLC, both of which were privately held oil and gas companies that he was brought in to take through troubled workout solutions. Prior to this, he was Senior Vice President of Exploration and Production for Cabot Oil and Gas (NYSE: COG). Mr. Trimble was hired in July 2002 as CEO of TexCal (formerly Tri-Union Development) to manage a distressed oil and gas company through bankruptcy, and that company filed for Chapter 11 reorganization within 45 days after the date that Mr. Trimble accepted such employment. He successfully managed the company through its exit from bankruptcy in 2004. From November 2002 until May 2006, he also served as a director of Blue Dolphin Energy, an independent oil & gas company with operations in the Gulf of Mexico. Mr. Trimble serves as Chairman of the Executive Committee and serves on the Planning and Finance Committee.

Gysle R. Shellum was appointed Chief Financial Officer in 2008. Prior to joining the Company, Mr. Shellum served as Vice President, Finance and Special Projects of Crosstex Energy, L.P., Dallas, Texas. Mr. Shellum served in this capacity from September 2004 through September 2008. From March 2001 until September 2004, Mr. Shellum served as a consultant to Value Capital, a private consulting firm in Dallas, Texas, where he worked on various projects, including corporate finance and Sarbanes-Oxley Act compliance. Crosstex Energy, L.P. is a publicly traded Delaware limited partnership whose securities are listed on the NASDAQ Global Select Market and is an independent midstream energy company engaged in the gathering, transmission, treating, processing and marketing of natural gas and natural gas liquids.

R. Scott Meyers was appointed Chief Accounting Officer on April 2, 2009. Prior to joining PDC, Mr. Meyers served as a Senior Manager with Schneider Downs Co., Inc., an accounting firm based in Pittsburgh, Pennsylvania.

Mr. Meyers served in such capacity from April 2008 to March 2009. Prior thereto, from November 2002 to March 2008, Mr. Meyers was employed by PricewaterhouseCoopers LLP, the last two and one-half years serving as Senior Manager.

Barton R. Brookman, Jr. was appointed Senior Vice President Exploration and Production in March 2008. Previously, Mr. Brookman served as Vice President Exploration and Production since joining PDC in July 2005. Prior to joining PDC, Mr. Brookman worked for Patina Oil and Gas and its predecessor Snyder Oil for 17 years in a series of positions of increasing responsibility, ending his service as Vice President of Operations of Patina.

Daniel W. Amidon was appointed General Counsel and Secretary in July 2007. Prior to his current position, Mr. Amidon was employed by Wheeling-Pittsburgh Steel Corporation beginning in July 2004; he served in several positions including General Counsel and Secretary. Prior to his employment with Wheeling-Pittsburgh Steel, Mr. Amidon worked for J&L Specialty Steel Inc. from 1992 through July 2004 in positions of increasing responsibility, including General Counsel and Secretary. Mr. Amidon practiced with the Pittsburgh law firm of Buchanan Ingersoll PC from 1986 through 1992.

Lance Lauck was appointed Senior Vice President Business Development in August 2009. Previously Mr. Lauck served as Vice President — Acquisitions and Business Development for Quantum Resources Management LLC from 2006 — 2009. From 1988 until 2006, he held various management positions at Anadarko Petroleum Corporation in the areas of acquisitions and divestitures, corporate mergers and business development.

Jeffrey C. Swoveland was appointed as the Chairman of the Board of Directors of PDC in June 2011. Mr. Swoveland is President and Chief Executive Officer of ReGear Life Sciences, Inc. in Pittsburgh, Pennsylvania (previously named Coventina Healthcare Enterprises), which develops and markets medical device products, where he was previously Chief Operating Officer. From 2000 until 2007, Mr. Swoveland served as Chief Financial Officer of Body Media, Inc., a life-science company specializing in the design and development of wearable body monitoring products and services. Prior thereto, Mr. Swoveland held various positions, including Vice-President of Finance, Treasurer and interim Chief Financial Officer with Equitable Resources, Inc., a diversified natural gas company, from 1994 to September 2000. Mr. Swoveland serves as a member of the Board of Directors of Linn Energy, LLC, a public, independent natural gas and oil company. Mr. Swoveland serves on the Audit Committee, the Planning and Finance Committee, the Compensation Committee and the Executive Committee.

Joseph E. Casabona served as Executive Vice President and member of the Board of Directors of Denver-based Energy Corporation of America, a natural gas exploration and development company, from 1985 until his retirement in May 2007. Mr. Casabona’s responsibilities included strategic planning as well as executive oversight of drilling operations in the continental U.S. and internationally. From 2008 until the beginning of 2011, Mr. Casabona served as Chief Executive Officer of Paramax Resources Ltd, a junior public Canadian oil & gas company (PMXRF) engaged in the business of acquiring and exploration of oil and gas prospects, primarily in Canada and Idaho. Mr. Casabona serves as Chairman of the Planning and Finance Committee and serves on the Audit Committee.

Anthony J. Crisafio, a Certified Public Accountant, has served as an independent business consultant for more than fifteen years, providing financial and operational advice to businesses in a variety of industries and stages of development. He is currently serving as interim contract Chief Financial Officer for Empire Energy USA, LLC. He also serves as an interim Chief Financial Officer and Advisory Board member for a number of privately held companies and has been a Certified Public Accountant for more than thirty years. Mr. Crisafio served as the Chief Operating Officer, Treasurer and member of the Board of Directors of Cinema World, Inc. from 1989 until 1993. From 1975 until 1989, he was employed by Ernst & Young and was a partner with Ernst & Young from 1986 to 1989. He was responsible for several Securities and Exchange Commission (“SEC”) registered client engagements and gained significant experience with oil and gas industry clients and mergers and acquisitions. Mr. Crisafio serves as the Chairman of the Audit Committee and serves on the Compensation Committee.

Larry F. Mazza is President and Chief Executive Officer of MVB Bank, Inc., a bank holding company with multiple banks in West Virginia. He has been Chief Executive Officer since March 2005, and added the duties of President in January of 2009. Prior to 2005, Mr. Mazza served as Senior Vice President Retail Banking for BB&T and its predecessors in West Virginia, where he was employed from June 1986 to March 2005. A Certified Public

Accountant for 26 years, Mr. Mazza also was previously an auditor with KPMG. Mr. Mazza serves as the Chairman of the Nominating and Governance Committee and serves on the Compensation Committee.

David C. Parke is a Managing Director in the investment banking group of Burrill & Company. From 2006 until June 2011, he was a Managing Director of Boenning & Scattergood, Inc., a full-service investment banking firm. Prior to joining Boenning & Scattergood in November 2006, he was a Director with Mufson Howe Hunter & Company LLC, Philadelphia, Pennsylvania, an investment banking firm, from October 2003 to November 2006. From 1992 through 2003, Mr. Parke was Director of Corporate Finance of Investec, Inc. and its predecessor Pennsylvania Merchant Group Ltd., investment banking companies. Prior to joining Pennsylvania Merchant Group, Mr. Parke served in the corporate finance departments of Wheat First Butcher & Singer, now part of Wachovia Securities, and Legg Mason, Inc., now part of Stifel Nicolaus. Mr. Parke serves on the Planning and Finance Committee, the Compensation Committee and on the Nominating and Governance Committee.

Kimberly Luff Wakim, an attorney and a Certified Public Accountant, is a Partner with the Pittsburgh, Pennsylvania law firm Thorp, Reed & Armstrong LLP, where she serves as a member of the Executive Committee and is the Practice Group Leader for the Bankruptcy and Financial Restructuring Practice Group. Ms. Wakim has practiced law with Thorp, Reed & Armstrong LLP since 1990. Ms. Wakim was previously an auditor with Main Hurdman (now KPMG) and was Assistant Controller for PDC from 1982 to 1985. She has been a member of AICPA and the West Virginia Society of CPAs for more than fifteen years. Ms. Wakim serves as Chairman of the Compensation Committee and serves on the Audit Committee and the Nominating and Governance Committee.

PDC’s Audit Committee

The PDC Audit Committee is composed entirely of persons whom the PDC board of directors has determined to be independent under NASDAQ Listing Rule 5605(a)(2), Section 301 of the Sarbanes-Oxley Act of 2002 and Section 10A(m)(3) of the Exchange Act. Anthony J. Crisafio chairs the PDC Audit Committee; other members are directors Wakim, Casabona and Swoveland. The PDC board of directors has determined that all four members of the Audit Committee qualify as financial experts as defined by SEC regulations and that all of the Audit Committee members are independent of management.

The business contact information for each of the above-named executive officers and directors is 1775 Sherman Street, Suite 3000, Denver, Colorado 80203, c/o Petroleum Development Corporation. To PDC’s knowledge, none of its executive officers or directors has been convicted in a criminal proceeding during the past five years (excluding traffic violations or similar misdemeanors) or has been a party to any judicial or administrative proceeding during the past five years (except for matters that were dismissed without sanction or settlement) that resulted in a judgment, decree, or final order enjoining the person from future violations of, or prohibiting activities subject to, federal or state securities laws, or a finding of any violation of federal or state securities laws. Each of PDC’s executive officers and directors is a citizen of the United States.

The Merger Sub

The following information sets forth the age, positions and offices with the merger sub of each manager and executive officer of the merger sub. Each such person has served in each of the capacities indicated opposite his name since the inception of the merger sub. Information with respect to each such person’s business experience during the past five years is set forth above under the heading “— PDC.”

The Partnership

PDC, in its capacity as the managing general partner of the partnership, has the exclusive right and full authority to manage, control and administer the partnership’s business. The partnership does not have any officers or directors of its own.

Additional Information

None of PDC, the partnership or the merger sub has been convicted in a criminal proceeding during the past five years (excluding traffic violations or similar misdemeanors), and none of PDC, the partnership or the merger sub has been a party to any judicial or administrative proceeding during the past five years (except for matters that were dismissed without sanction or settlement) that resulted in a judgment, decree or final order enjoining it from future violations of, or prohibiting activities subject to, federal or state securities laws, or a finding of any violation of federal or state securities laws.

None of the officers or directors of PDC or the merger sub has been convicted in a criminal proceeding during the past five years (excluding traffic violations or similar misdemeanors), and none of such persons has been a party to any judicial or administrative proceeding during the past five years (except for matters that were dismissed without sanction or settlement) that resulted in a judgment, decree or final order enjoining him or her from future violations of, or prohibiting activities subject to, federal or state securities laws, or a finding of any violation of federal or state securities laws.

There is no agreement or understanding, whether written or unwritten, between any of the executive officers of PDC, the merger sub or the partnership, concerning any type of compensation whether present, deferred or contingent, that is based on or otherwise relates to the merger.

RESERVE REPORT

Appendix D to this document sets forth the partnership’s reserve report as of December 31, 2010. You should read Appendix D carefully in its entirety.

The reserve report for the partnership set forth in Appendix D to this document was prepared by Ryder Scott Company, L.P., an independent petroleum consultant. The proved reserves and estimated future net revenues attributable to the partnership has been included in this document in reliance on that firm’s authority as experts on the matters contained in that reserve report.

SUMMARY FINANCIAL INFORMATION

Set forth below is summary financial data relating to the partnership. The financial data has been derived from the partnership’s audited financial statements as of December 31, 2010 and 2009 and for the years then ended and unaudited financial statements as of June 30, 2011 and 2010 and for the periods then ended, which are included as Appendix E to this proxy statement. You should read Appendix E carefully in its entirety. The following data should be read in conjunction with Appendix E and other financial information contained in the partnership’s Form 10-K for year ended December 31, 2010 and the Form 10-Q for quarter ended June 30, 2011.


	Three Months Ended						Six Months Ended					Year Ended
	June 30,						June 30,					December 31,
	2011			2010			2011			2010		2010			2009

Statement of Operations Data:
Revenues	$	425,286		$	478,966		$	733,719		$	1,345,325	$	2,248,373		$	785,263
Operating Costs and Expenses		364,756			610,179			929,171			1,311,559		3,416,374			1,843,741
(Loss) Income from Operations		60,530			(131,213	)		(195,452	)		33,766		(1,168,001	)		(1,058,478	)
Net (Loss) Income		60,558			(131,167	)		(195,375	)		33,859		(1,167,810	)		(1,038,892	)
Net (Loss) Income Allocated to Partners		60,558			(131,167	)		(195,375	)		33,859		(1,167,810	)		(1,038,892	)
Less: Managing General Partner Interest in Net (Loss) Income		12,112			(26,233	)		(39,075	)		6,772		(233,562	)		(207,778	)
Net (Loss) Income Allocated to Investor Partners		(48,446	)		(104,934	)		(156,300	)		27,087		(934,248	)		(831,114	)
Net (Loss) Income per Investor Partner Unit		33			(72	)		(107	)		19		(642	)		(571	)
Net (Loss) Income from Operations per Investor Partner Unit		33			(72	)		(107	)		19		(642	)		(582	)
Investor Partner Units Outstanding		1,455.26			1,455.26			1,455.26			1,455.26		1,455.26			1,455.26
Ratio of Earning to Fixed Charges (unaudited)			*			*		*			*			*		147.65


*		There were no fixed charges during the reported period.


	June 30,		December 31,
	2011		2010		2009

Balance Sheet Data:
Current Assets	$	533,428	$	652,850	$	564,626
Non-Current Assets		6,225,584		6,705,863		8,088,744
Total Assets		6,759,012		7,358,713		8,653,370
Current Liabilities		646,820		925,534		214,719
Non-Current Liabilities		786,845		872,135		1,037,885
Total Liabilities		1,433,665		1,797,669		1,252,604
Partners’ Equity:
Managing General Partner		1,263,156		1,306,336		1,597,595
Limited Partners — 1,455.26 Units Issued and Outstanding		4,062,191		4,254,708		5,803,171
Total Partners’ Equity		5,325,347		5,561,044		7,400,766
Book Value per Investor Partner Unit (unaudited)		2,791		2,924		3,988

PROPOSAL 3 — ADJOURNMENT OF THE SPECIAL MEETING

If at the special meeting the number of limited partnership units of the partnership present or represented by proxy and voting in favor of the approval of the merger agreement or the amendment to the partnership agreement is insufficient to approve the merger agreement or the amendment to the partnership agreement, respectively, under West Virginia law and under the partnership agreement, PDC (in its capacity as the managing general partner of the partnership) may move to adjourn the special meeting in order to enable PDC to continue to solicit additional proxies in favor of the approval of the merger agreement and the amendment to the partnership agreement. In that event, PDC will ask you to vote only upon the adjournment proposal and not on the merger agreement or the amendment to the partnership agreement.

In this proposal, the special committee is asking you to authorize the holder of your proxy to vote in favor of adjourning the special meeting and any later adjournments. If the investors approve the adjournment proposal, PDC will adjourn the special meeting, and any adjourned session of the special meeting, and use the additional time to solicit additional proxies in favor of the proposal to approve the merger agreement and the amendment to the partnership agreement, including the solicitation of proxies from investors who have previously voted against the merger agreement or the amendment to the partnership agreement. Among other things, approval of the adjournment proposal could mean that, even if PDC had received proxies representing a sufficient number of votes against the proposal to approve the merger agreement or the proposal to amend the partnership agreement to defeat either such proposal, PDC could adjourn the special meeting without a vote on either such proposal and seek to convince the holders of those limited partnership units voting against either or both proposals to change their votes to votes in favor of both proposals.

The adjournment proposal requires that holders of more of the limited partnership units vote in favor of the adjournment proposal than vote against the proposal. Accordingly, abstentions and broker non-votes will have no effect on the outcome of this proposal. No proxy that is specifically marked “AGAINST” the proposal to approve the merger agreement or the amendment to the partnership agreement will be voted in favor of the adjournment proposal, unless it is specifically marked “FOR” the discretionary authority to adjourn the special meeting to a later date.

The special committee believes that if the number of limited partnership units present or represented by proxy at the special meeting and voting in favor of the merger agreement or the amendment to the partnership agreement is insufficient to approve the merger agreement or the amendment to the partnership agreement, respectively, it is in the best interests of the investors to enable PDC, for a limited period of time, to continue to seek to obtain a sufficient number of additional votes to approve the merger agreement and/or the amendment to the partnership agreement.

THE SPECIAL COMMITTEE RECOMMENDS A VOTE “FOR” THE APPROVAL OF ANY PROPOSAL TO ADJOURN OR POSTPONE THE SPECIAL MEETING TO A LATER DATE, INCLUDING AN ADJOURNMENT OR POSTPONEMENT TO SOLICIT ADDITIONAL PROXIES IF, AT THE SPECIAL MEETING, THE NUMBER OF LIMITED PARTNERSHIP UNITS PRESENT OR REPRESENTED BY PROXY AND VOTING IN FAVOR OF THE APPROVAL OF THE MERGER AGREEMENT OR THE AMENDMENT TO THE PARTNERSHIP AGREEMENT IS INSUFFICIENT TO APPROVE THE MERGER AGREEMENT OR THE AMENDMENT OF THE PARTNERSHIP AGREEMENT, RESPECTIVELY.

OTHER MATTERS

Only the business that is specified in the “Notice of Special Meeting of Investors” may be presented at the special meeting, and no other matters may properly be brought before the special meeting. The partnership is unaware of other matters to be voted on at the special meeting. If other matters do properly come before the special meeting, the partnership intends that the persons named in the proxies will vote, or not vote, in their discretion the limited partnership units represented by the proxies.

ADDITIONAL BUSINESS INFORMATION

Petroleum Development Corporation

PDC, a Nevada corporation, is an independent energy company engaged in the exploration, development, production and marketing of crude oil, NGLs and natural gas. Since it began oil and gas operations in 1969, PDC has grown through drilling and development activities, acquisitions of producing natural gas and oil wells and the expansion of its natural gas marketing activities. PDC also serves as the managing general partner of 26 partnerships formed to drill, own and operate natural gas and oil wells, including PDC 2002-D Limited Partnership.

PDC’s common stock is traded on the NASDAQ Global Select Market under the ticker symbol “PETD.” PDC files annual, quarterly and current reports, proxy statements and other information with the United States Securities and Exchange Commission, or SEC. Those SEC filings are available to you in the same manner as the partnership’s information. See “Where You Can Find More Information.”

The principal executive office of PDC is located at 1775 Sherman Street, Suite 3000, Denver, Colorado 80203, and its telephone number is 303-860-5800.

PDC, in its capacity as managing general partner of the partnership, prepared this document to solicit your proxy.

DP 2004 Merger Sub, LLC

The merger sub is a direct, wholly-owned subsidiary of PDC and was formed as a limited liability company under the laws of the State of Delaware. The merger sub was formed on May 7, 2010 solely for the purpose of effecting the merger of PDC’s drilling partnerships. The merger sub has not conducted any business operations other than activities incidental to its formation and in connection with the transactions contemplated by the merger and the acquisitions of the 2004 partnerships and the 2005 partnerships.

The principal executive office of the merger sub is located at 1775 Sherman Street, Suite 3000, Denver, Colorado 80203, and its telephone number is 303-860-5800.

PDC 2002-D Limited Partnership

General

The partnership is a publicly subscribed West Virginia Limited Partnership which owns an undivided working interest in natural gas and crude oil wells located in Colorado from which the partnership produces and sells natural gas, NGLs and crude oil. The partnership was organized and began operations in 2002 with cash contributed by limited and additional general partners, who own 80% of the partnership’s capital, or equity interests, and PDC, who owns the remaining 20% of the partnership’s capital, or equity interest. PDC serves as managing general partner of the partnership. Upon funding, the partnership entered into a Drilling and Operating Agreement, which we refer to as the D&O Agreement, with PDC that governs the drilling and operational aspects of the partnership.

In accordance with the partnership agreement, general partnership interests were converted to limited partnership units at the completion of the partnership’s drilling activities. The partnership expended substantially all of the capital raised in the offering for the initial drilling and completion of the partnership’s wells.

The following table presents partnership formation and organizational information through the completion of the drilling phase on October 20, 2003:


					Number of Partner
					Units
					Additional
					General			Limited
PDC 2002-D Limited			Number of		Partner			Partner			Equity
Partnership Information	Date		Partners		Units			Units			Percentage			Amount
														(Millions)

West Virginia Limited Partnership Formation		June 3, 2002
Limited Partnership Termination Date		December 31, 2050
Public Sale of Securities and Funding		December 31, 2002
Investor Partners⁽¹⁾ Unit Cost: $20,000				1,163		1,422.11			33.15			80.00	%	$	29.1
PDC, Managing General Partner												20.00	%		6.3

Total funding															35.4
Syndication costs paid to third-party brokers															(3.1	)
Management fee paid to PDC															(0.7	)

Net funding available for drilling activities												100.00	%	$	31.6

Conversion of Additional General Partners to Limited Partners		October 20, 2003				(1,422.11	)		(1,422.11	)

Limited partnership units after conversion						—			1,455.26


(1)		PDC, as managing general partner of the partnership, repurchases investor’s units under certain circumstances provided by the partnership agreement, upon request of an individual investor. For more information about PDC’s limited partner unit repurchase program, see “— Unit Repurchase Program”.

The partnership expects continuing operations of its natural gas and crude oil properties until such time the partnership’s wells are depleted or become uneconomical to produce, at which time that well may be sold or plugged, reclaimed and abandoned. The partnership’s maximum term of existence extends through December 31, 2050, unless dissolved by certain conditions stipulated within the partnership agreement which are unlikely to occur at this time, or by written consent of the investors owning a majority of outstanding units at that time.

The address and telephone number of the partnership and PDC’s principal executive offices are 1775 Sherman Street, Suite 3000, Denver, Colorado 80203 and (303) 860-5800.

Business Strategy

The primary objective of the partnership is the profitable operation of developed Colorado natural gas and crude oil properties and the appropriate allocation of cash proceeds, costs and tax benefits, based on the terms of the partnership agreement, among the partnership’s investors. The partnership operates in one business segment, natural gas, NGLs and crude oil sales.

The partnership’s business plan going forward, including the Additional Codell Formation Development Plan, is to produce and sell the natural gas, NGLs and crude oil from the partnership’s wells, and to make distributions to the partners. Partnership cash distributions may be withheld pursuant to the Additional Codell Formation Development Plan.

Operations

General. When partnership wells were “completed” (i.e., drilled, fractured or stimulated, and all surface production equipment and pipeline facilities necessary to produce the well were installed) production operations commenced on each well. All partnership wells are completed, and production operations are currently being conducted with regard to each of the partnership’s productive wells.

PDC, in accordance with the D&O Agreement, is the named operator of record of the partnership’s wells and may, in certain circumstances, provide equipment and supplies, perform salt water disposal and other services for the partnership. Generally, equipment and services are sold to the partnership at the lower of cost or competitive prices in the area of operations. The partnership’s share of production revenue from a given well is burdened by and subject to, royalties and overriding royalties, monthly operating charges, production taxes and other operating costs. It is PDC’s practice to deduct operating expenses from the production revenue for the corresponding period. In instances when distributable cash flows are insufficient to make full payment, PDC defers the collection of operating expenses until such time as scheduled expenses may be offset against future partnership distributable cash flows. In such instances, the partnership records a liability to PDC.

The partnership’s operations are concentrated in the Rocky Mountain Region where weather conditions and time periods reserved by leasehold restrictions can exist and limit operational capabilities for as long as six months. Operational constraint challenges such as surface equipment freezing can limit production volumes. Increased competition for oil field equipment, services, supplies and qualified personnel and wildlife habitat protection periods may also adversely affect profitability and reduce cash distributions to the investors.

Areas of Operations

The partnership’s operating areas are profiled as follows:

Wattenberg Field, DJ Basin, Weld County, Colorado. Located north and east of Denver, Colorado, the partnership’s wells in this field exhibit production histories typical for other wells located in this field with an initial high production rate and relatively rapid decline, followed by years of relatively lower rates of decline and production levels. Although natural gas is the primary hydrocarbon produced, many wells also produce NGLs or oil. Of the partnership’s 27 wells drilled in the Wattenberg Field, 21 wells were initially completed and 20 currently produce from the Codell formation as one well was not in production at the end of 2010. Six of these Codell formation wells were also completed and produce from the shallower Niobrara formation. The remaining six productive Wattenberg Field wells were initially completed and currently produce from the deeper J-Sand formation. The partnership’s development wells in this area are generally 7,000 to 8,000 feet in depth. Well spacing ranges from 20 to 40 acres per well.

Grand Valley Field, Piceance Basin, Garfield County, Colorado. Located near the western border of Colorado, the partnership’s nine wells in this field have also exhibited production histories typical for other wells located in this field with an initial high production rate and relatively rapid decline, followed by years of relatively lower rates of decline and production levels. These wells generally produce natural gas along with small quantities of crude oil. The majority of the partnership’s development wells drilled in the area were drilled directionally from multi-well pads ranging from two to eight or more wells per drilling pad. The primary drilling targets were multiple sandstone reservoirs in the Mesa Verde formation and well depth ranges from 7,000 to 9,500 feet. Well spacing is approximately 10 acres per well.

Title to Properties

The partnership’s leases are direct interests in producing acreage. In accordance with the D&O Agreement, PDC exercised due care and judgment, which included curative work for any title defect when discovered, to ensure that each partnership’s well bore working interest assignment, made effective on the date of well spudding, was properly recorded in county land records. The partnership believes it holds good and defensible title to its developed properties, in accordance with standards generally accepted in the industry, through the record title held in the partnership’s name, of each partnership well’s working interest. The partnership’s properties are subject to royalty, overriding royalty and other outstanding interests customary to the industry. PDC is not aware of any additional burdens, liens or encumbrances customary to the industry, if any, which may materially interfere with the commercial use of the properties. Provisions of the partnership agreement generally relieve PDC from errors in judgment with respect to the waiver of title defects.

Drilling and Other Development Activities

Natural Gas and Crude Oil Properties. The partnership’s properties (the “Properties”) consist of a working interest in the well bore in each well drilled by the partnership. The partnership drilled 36 development wells (32.3 net) (the number of gross wells multiplied by the working interest in the wells owned by the partnership) during drilling operations that began immediately after funding and concluded in August 2003 when the last of the partnership’s 36 productive wells were connected to sales and gathering lines. No exploratory drilling activity was conducted on behalf of the partnership. The 36 wells discussed above are the only wells to be drilled by the partnership since all of the funds raised in the partnership offering have been expended.

The following table presents the partnership’s productive wells by operating field as of December 31, 2010 and 2009. Productive wells consist of producing wells and wells capable of producing natural gas and/or NGLs and crude oil in commercial quantities.


	Producing Gas Wells
	2010				2009
Location	Gross		Net		Gross		Net

State of Colorado
Piceance Basin: Grand Valley Field		9.0		9.0		9.0		9.0
Denver-Julesburg (DJ) Basin: Wattenberg Field		26.0		22.4		26.0		22.4

Total Colorado		35.0		31.4		35.0		31.4

Total Productive Wells(1)		35.0		31.4		35.0		31.4


(1)		Not included in the productive well statistics above is one Wattenberg Field partnership well (0.9 net) temporarily not in production at December 31, 2010 and 2009, due to equipment problems.

Additional Codell Formation Development Plan. For information about the “Additional Codell Formation Development Plan” see “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Additional Codell Formation Development Plan.”

Proved Reserves

All of the partnership’s proved reserves are located in the United States. The partnership’s reserve estimates are prepared with respect to reserve categorization, using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a), and subsequent SEC staff regulations, interpretations and guidance. All of the partnership’s proved reserves have been estimated by independent engineers.

PDC, as managing general partner of the partnership, established a comprehensive process that governs the determination and reporting of the partnership’s proved reserves. As part of PDC’s internal control process, the partnership’s reserves are reviewed annually by a team composed of PDC reservoir engineers, geologists and accounting personnel for adherence to SEC guidelines through a detailed review of land records, available geological and reservoir data as well as production performance data. The review includes, but is not limited to, confirmation that reserve estimates (1) include all properties owned; (2) are based on proper working and net revenue interests; and (3) reflect reasonable cost estimates and field performance. The internal team compiles the reviewed data and forwards the data to an independent consulting firm engaged to estimate the partnership’s reserves.

The partnership utilized the services of an independent petroleum engineer, Ryder Scott Company, L.P. (Ryder Scott), to estimate the partnership’s 2010 and 2009 reserves. When preparing the partnership’s reserve estimates, the independent engineer did not independently verify the accuracy and completeness of information and data furnished by PDC with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices, or any agreements relating to current and future operations of properties and sales of production.

The independent petroleum engineer prepared an estimate of the partnership’s reserves in conjunction with an ongoing review by PDC’s engineers. A final comparison of data was performed to ensure that the reserve estimates

were complete, determined by acceptable industry methods and to a level of detail that PDC deems appropriate. The final independent petroleum engineer’s estimated reserve report was reviewed and approved by PDC’s engineering staff and management.

The professional qualifications of PDC’s lead engineer primarily responsible for overseeing the preparation of the partnership’s reserve estimate meets the standards of Reserves Estimator as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers. This PDC employee holds a Bachelor of Science degree in Petroleum and Natural Gas Engineering and has over 25 years of experience in reservoir engineering. The individual is a member of the Society of Petroleum Engineers, allowing the individual to remain current with the developments and trends in the industry. Further, during 2009, this individual attended ten hours of formalized training relating to the definitions and disclosure guidelines set forth in the SEC’s final rule released January 2009, Modernization of Oil and Gas Reporting.

Proved reserves are those quantities of natural gas, NGLs and crude oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. These reserve quantities are projected to be producible prior to the operating contract’s expiration date, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. The partnership’s net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. The partnership’s two categories of proved reserves are as follows:


	•	Proved developed reserves are those natural gas, NGLs and crude oil quantities expected to be recovered from currently producing zones under the continuation of present operating methods.

	•	Proved undeveloped reserves, or PUDs, are those reserves expected to be recovered from existing wells where a relatively major expenditure is required for recompletion or refracturing.

The table below presents information regarding the partnership’s estimated proved reserves. Prior to 2010, the partnership’s NGLs reserves were included in and reported with natural gas reserves, which impacts the comparability of 2010 reserve information to previously reported 2009 reserve information. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Reporting on NGLs in 2010.”

Reserves cannot be measured exactly, because reserve estimates involve judgments. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance data, new geological and geophysical data and economic changes. The partnership’s estimated proved undeveloped reserves consist entirely of reserves attributable to the Wattenberg Field’s future initial Codell formation recompletion of six productive J-Sand wells and future refracturing of 26 of the partnership’s Codell formation wells. There were no proved undeveloped reserves that were developed in 2010. See “Additional Business Information-Drilling and Other Activities- Additional Codell Formation Development Plan.”


	December 31,
	2010

Proved Reserves
Natural gas (MMcf)		2,416
Crude Oil and Condensate (MBbl)		308
NGLs (MBbl)		116
Total proved reserves (MMcfe)		4,960

An economically producible quantity is one where the revenue provided by its sale is reasonably likely to exceed the cost to deliver that quantity to market. Prices used to estimate future gross revenues and production and development costs considered in the estimation of economically producible natural gas, NGLs and crude oil reserve quantities presented above, were based on the following:

Gross revenues


	•	A 12-month average price calculated as the unweighted arithmetic average of the price on the first day of each month, January through December.

	•	Prices were adjusted by lease for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of the partnership’s commodity hedges.

Production and development costs


	•	Costs as of December 31 for each of the respective years presented.

	•	The amounts shown do not give effect to non-property related expenses, such as direct costs-general and administrative expenses or to depreciation, depletion and amortization expense.

The following table presents the partnership’s estimated proved reserves by type and by field:


	As of December 31, 2010
					Crude Oil and		Natural Gas
	Natural Gas		NGLs		Condensate		Equivalent
	(MMcf)		(MBbl)		(MBbl)		(MMcfe)		Percent

Proved developed
Piceance Basin: Grand Valley Field		225		—		—		225		20	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		388		25		58		886		80	%

Total proved developed		613		25		58		1,111		100	%

Proved undeveloped
Piceance Basin: Grand Valley Field		—		—		—		—		0	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		1,803		91		250		3,849		100	%

Total proved undeveloped		1,803		91		250		3,849		100	%

Proved reserves
Piceance Basin: Grand Valley Field		225		—		—		225		5	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		2,191		116		308		4,735		95	%

Total proved reserves		2,416		116		308		4,960		100	%

Production, Sales, Prices and Lifting Costs — By Field

The following table presents information regarding the partnership’s production volumes, natural gas, NGLs and crude oil sales, average sales price received and average production cost by field. Prior to 2010, NGLs were included in natural gas. As a result for the Denver-Julesberg (DJ) Basin: Wattenberg Field information, natural gas production, sales and average sales price comparability are impacted for 2010 to 2009. However, total production at the Mcfe level, sales by field and average price per Mcfe are comparable.


	Year Ended December 31,
	2010		2009

Production⁽¹⁾
Natural gas (Mcf)
Piceance Basin: Grand Valley Field		128,689		147,834
Denver-Julesberg (DJ) Basin: Wattenberg Field		57,171		88,523

Total Natural Gas		185,860		236,357
Crude Oil (Bbl)
Piceance Basin: Grand Valley Field		311		540
Denver-Julesberg (DJ) Basin: Wattenberg Field		7,624		9,389

Total Crude Oil		7,935		9,929
NGLs (Bbl)
Denver-Julesberg (DJ) Basin: Wattenberg Field		3,418		—
Natural gas equivalent (Mcfe)
Piceance Basin: Grand Valley Field		130,555		151,074
Denver-Julesberg (DJ) Basin: Wattenberg Field		123,423		144,857

Total natural gas equivalent		253,978		295,931

Natural Gas, NGLs and Crude Oil Sales
Natural gas sales
Piceance Basin: Grand Valley Field	$	449,193	$	401,097
Denver-Julesberg (DJ) Basin: Wattenberg Field		206,568		369,569

Total natural gas sales		655,761		770,666
Crude oil sales
Piceance Basin: Grand Valley Field	$	19,326	$	21,924
Denver-Julesberg (DJ) Basin: Wattenberg Field		562,734		489,082

Total crude oil sales		582,060		511,006
NGLs sales
Denver-Julesberg (DJ) Basin: Wattenberg Field	$	149,203	$	—
Natural gas, NGLs and crude oil sales
Piceance Basin: Grand Valley Field	$	468,519	$	423,021
Denver-Julesberg (DJ) Basin: Wattenberg Field		918,505		858,651

Total natural gas, NGLs and crude oil sales	$	1,387,024	$	1,281,672

Average Sales Price (excluding realized gain on derivatives)
Natural gas (per Mcf)
Piceance Basin: Grand Valley Field	$	3.49	$	2.71
Denver-Julesberg (DJ) Basin: Wattenberg Field		3.61		4.17
Average sales price natural gas, both fields		3.53		3.26
Crude Oil (per Bbl)
Piceance Basin: Grand Valley Field	$	62.14	$	40.60
Denver-Julesberg (DJ) Basin: Wattenberg Field		73.81		52.09
Average sales price crude oil, both fields		73.35		51.47
NGLs (per Bbl)
Denver-Julesberg (DJ) Basin: Wattenberg Field	$	43.65	$	—
Natural gas equivalent (per Mcfe)
Piceance Basin: Grand Valley Field	$	3.59	$	2.80
Denver-Julesberg (DJ) Basin: Wattenberg Field		7.44		5.93
Average sales price natural gas equivalents, both fields		5.46		4.33
Average Production (Lifting) Cost⁽²⁾ (per Mcfe)
Piceance Basin: Grand Valley Field	$	4.63	$	2.43
Denver-Julesberg (DJ) Basin: Wattenberg Field		3.55		1.55
Average production cost, both fields		4.11		2.00


(1)		Production is net and determined by multiplying the gross production volume of properties in which the partnership has an interest by the percentage of the leasehold or other property interest the partnership owns.

(2)		Average production unit costs presented exclude the effects of ad valorem and severance taxes.

For more information concerning the partnership’s production volumes and costs, which include severance and ad valorem taxes as reflected in the Partnership’s statements of operations accompanying this proxy statement, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this proxy statementt.

Natural Gas, NGLs and Crude Oil Sales

In accordance with the D&O Agreement, PDC markets the natural gas, NGLs and crude oil produced from the partnership’s wells primarily to other gas marketers, utilities, industrial end-users and other wholesale gas purchasers. PDC generally sells the natural gas that the partnership produces under contracts with indexed monthly pricing provisions. PDC does not charge an additional fee for the marketing of the natural gas, NGLs and crude oil because these services are covered by the monthly well operating charge. This monthly charge is more fully described in the section entitled “Additional Business Information-Reliance on the Managing General Partner, Provisions of the D&O Agreement.” Virtually all of the partnership’s contracts include provisions wherein prices change monthly with changes in the market, for which certain adjustments may be made based on whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the partnership’s revenues from the sale of natural gas, holding production volume constant, increase as market prices increase and decrease as market prices decline. PDC believes that the pricing provisions of the partnership’s natural gas contracts are customary in the industry. PDC also enters into financial derivatives in order to reduce the impact of possible price instability regarding the physical sales market.

In general, PDC has been and expects to continue to be able to produce and sell natural gas and NGLs from the partnership’s wells without significant curtailment and at competitive prices. The partnership does, however, experience limited curtailments from time to time due to pipeline maintenance and operating issues. Open access transportation through the country’s interstate pipeline system gives us access to a broad range of markets. Whenever feasible, PDC obtains access to multiple pipelines and markets from each of the partnership’s gathering systems, seeking the best available market for the partnership’s natural gas at any point in time.

The wells in the partnership’s Wattenberg Field and, to a significantly lesser extent, the Grand Valley Field wells, produce crude oil as well as natural gas and NGLs. PDC is currently able to sell all the crude oil that the partnership can produce under existing sales contracts with petroleum refiners and marketers. The partnership does not refine any of the partnership’s crude oil production. The partnership’s crude oil production is sold to purchasers at or near the partnership’s wells under both short and long-term purchase contracts with monthly pricing provisions.

Transportation and Gathering

The partnership’s natural gas and NGLs are transported through PDC’s and third party gathering systems and pipelines, and the partnership incurs processing, gathering and transportation expenses to move the partnership’s natural gas and related NGLs from the wellhead to a purchaser-specified delivery point. These expenses vary based on the volume and distance shipped, and the fee charged by the third-party processor or transporter. Capacity on these gathering systems and pipelines is occasionally limited and at times unavailable because of repairs or improvements, or as a result of priority transportation agreements with other gas transporters. While PDC’s ability to market the partnership’s natural gas and NGLs have been only infrequently limited or delayed, if transportation space is restricted or is unavailable, the partnership’s cash flow from the affected properties could be adversely affected. In order to meet pipeline specifications, PDC is required, in some cases, to process the partnership’s natural gas before it can be transported. PDC typically contracts with third parties in the Grand Valley area of the Rocky Mountain Region for firm transportation of the partnership’s natural gas and NGLs.

Delivery Commitments

On behalf of the partnership, other sponsored drilling program partnerships and for its own corporate account, PDC has entered into third-party sales and processing agreements that generally contain indexed monthly pricing provisions. Although the partnership is not committed to deliver any fixed and determinable quantities of natural gas or oil under the terms of these agreements, the dedication of the partnership’s future production is as follows:


	•	Wattenberg Field contractual natural gas and NGLs processing and sales dedications are multi-year and extend throughout the well’s economic life.

	•	Grand Valley Field contractual natural gas processing and firm sales dedications extend through 2022 and the contract provides the seller with the right to convert to a gathering and gas processing contract, solely.

	•	Oil sales dedication is made under a 2-year master agreement with negotiated extensions.

Delivery to Market

The partnership relies on PDC owned or third-party gathering and transmission pipelines to transport natural gas and NGLs production volumes to customers. In general, the partnership has been, and expects to continue to be able to, produce and sell natural gas and NGLs from partnership wells without significant curtailment. The partnership does experience limited curtailments from time to time due to pipeline maintenance and operating issues of the pipeline operators.

Seasonal curtailment typically occurs during July and August as a result of high atmospheric temperatures which reduce compressor efficiency. This reduction in production typically amounts to less than five percent of normal monthly production. The cost, timing and availability of gathering pipeline connections and service varies from area to area, well to well, and over time. Although the Rockies Region has experienced a natural gas transport capacity shortage in the past several years, several key projects placed in-service during the past two years, including the completion of the 1,679-mile Rockies Express Pipeline which extends from Colorado to eastern Ohio and White River Header Pipeline Project in Colorado, have significantly increased natural gas deliverability to intra-regional urban areas as well as inter-regionally, especially to markets in the North Central and Northeastern U.S. as well as Southern California. Transmission capacity is expected to increase in the future based on projects scheduled before various regulatory agencies, but may be delayed due to the recent economic downturn which has weakened U.S. natural gas, NGLs and crude oil demand and disrupted global credit markets, which third-party entities access for pipeline expansion financing.

The partnership oil production is stored in tanks at or near the location of the partnership’s wells for routine pickup by oil transport trucks for direct delivery to regional refineries or oil pipeline interconnects for redelivery to those refineries. The cost of trucking or transporting the oil to market affects the price the partnership ultimately receives for the oil.

Commodity Price Risk Management Activities

PDC, as managing general partner of the partnership, on behalf of the partnership and in accordance with the D&O Agreement, utilizes commodity based derivative instruments to manage a portion of the partnership’s exposure to price volatility with regard to the partnership’s natural gas and crude oil sales. The financial instruments generally consist of collars, swaps and basis swaps and are NYMEX-traded and Colorado Interstate Gas, or CIG, based contracts. PDC may utilize derivatives based on other indices or markets where appropriate. The contracts economically provide price stability for committed and anticipated natural gas and crude oil sales, generally forecasted to occur within the next two to four-year period. The partnership’s policies prohibit the use of commodity derivatives for speculative purposes and permit utilization of derivatives only if there is an underlying physical position. PDC manages price risk on only a portion of the partnership’s anticipated production, so the remaining portion of the partnership’s production is subject to the full fluctuation of market pricing.

PDC uses financial derivatives to establish “floors” and “ceilings” or “collars” on the possible range of the prices realized for the sale of natural gas and crude oil in addition to fixing prices by using swaps. These derivatives

are carried on the balance sheets at fair value with changes in fair values recognized currently in the statement of operations.

The partnership is subject to price fluctuations for natural gas and crude oil sold in the spot market and under market index contracts. PDC continues to evaluate the potential for reducing these risks by entering into derivative transactions. In addition, PDC may close out any portion of derivatives that may exist from time to time which may result in a realized gain or loss on that derivative transaction.

Governmental Regulation

While the prices of natural gas, NGLs and crude oil are market driven, other aspects of the partnership’s business and the industry in general are heavily regulated. The availability of a ready market for natural gas, NGLs and crude oil production depends on several factors beyond the partnership’s control. These factors include regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of natural gas, NGLs and crude oil available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. State and federal regulations generally are intended to protect consumers from unfair treatment and oppressive control, to reduce the risk to the public and workers from the drilling, completion, production and transportation of natural gas, NGLs and crude oil, to prevent waste of natural gas, NGLs and crude oil, to protect rights among owners in a common reservoir and to control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies. In the western part of the U.S., the federal and state governments own a large percentage of the land and the rights to develop natural gas and crude oil. Generally, government leases are subject to additional regulations and controls not commonly seen on private leases. PDC takes the steps necessary to comply with applicable regulations, both on its own behalf and as part of the services provided to sponsored drilling partnerships. PDC believes that it is in compliance with such statutes, rules, regulations and governmental orders, although there can be no assurance that this is or will remain the case. The following summary discussion of the regulation of the U.S. oil and natural gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which the partnership’s operations may be subject.

Regulation of Natural Gas, NGLs and Crude Oil Production. The partnership’s production business is subject to various federal, state and local laws and regulations on the taxation of natural gas, NGLs and crude oil, the development, production and marketing of natural gas, NGLs and crude oil and environmental and safety matters. Many laws and regulations require drilling permits and govern the spacing of wells, rates of production, water discharge, prevention of waste and other matters. Prior to commencing drilling activities for a well, PDC must procure permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies in the state in which the area to be drilled is located. The permits and approvals include those for the drilling of wells. Additionally, other regulated matters include:


	•	bond requirements in order to drill or operate wells;

	•	the location of wells;

	•	the method of drilling and casing wells;

	•	the surface use and restoration of well properties;

	•	the plugging and abandoning of wells; and

	•	the disposal of fluids.

The partnership’s operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells which may be drilled and the unitization or pooling of properties. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is voluntary, it may be more difficult to form units, and therefore, more difficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws may establish maximum rates of production from natural gas and crude oil wells, generally prohibiting the venting or flaring of natural gas and imposing certain requirements regarding the ratability of production. Where wells are to be drilled

on state or federal leases, additional regulations and conditions may apply. The effect of these regulations may limit the amount of natural gas, NGLs and crude oil that can be produced from the partnership’s wells and may limit the number of wells or the locations which can be drilled. Such laws and regulations may increase the costs of planning, designing, drilling, installing, operating and abandoning the partnership’s natural gas and crude oil wells and other facilities. In addition, these laws and regulations, and any others that are passed by the jurisdictions where the partnership has production, could limit the total number of wells drilled or the allowable production from successful wells, which could limit the partnership’s reserves. As a result, PDC is unable to predict the future cost or effect of complying with such regulations.

Regulation of Sales and Transportation of Natural Gas. Historically, the price of natural gas was subject to limitation by federal legislation. The Natural Gas Wellhead Decontrol Act removed, as of January 1, 1993, all remaining federal price controls from natural gas sold in “first sales” on or after that date. The Federal Energy Regulatory Commission’s, or FERC, jurisdiction over natural gas transportation was unaffected by the Decontrol Act.

PDC, as managing general partner of the partnership, moves natural gas and NGLs through pipelines owned by other companies, and sells natural gas and NGLs to other companies that also utilize common carrier pipeline facilities. Natural gas pipeline interstate transmission and storage activities are subject to regulation by the FERC under the Natural Gas Act of 1938, or NGA, and under the Natural Gas Policy Act of 1978, and, as such, rates and charges for the transportation of natural gas in interstate commerce, accounting, and the extension, enlargement or abandonment of its jurisdictional facilities, among other things, are subject to regulation. Each natural gas pipeline company holds certificates of public convenience and necessity issued by the FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA. Each natural gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. FERC regulations govern how interstate pipelines communicate and do business with their affiliates. Interstate pipelines may not operate their pipeline systems to preferentially benefit their marketing affiliates.

Each interstate natural gas pipeline company establishes its rates primarily through the FERC’s rate-making process. Key determinants in the ratemaking process are:


	•	costs of providing service, including depreciation expense;

	•	allowed rate of return, including the equity component of the capital structure and related income taxes; and

	•	volume throughput assumptions.

The availability, terms and cost of transportation affect the partnership’s natural gas and NGLs sales. In the past, FERC has undertaken various initiatives to increase competition within the industry. As a result of initiatives like FERC Order No. 636, issued in April 1992, the interstate natural gas transportation and marketing system was substantially restructured to remove various barriers and practices that historically limited non-pipeline natural gas sellers, including producers, from effectively competing with interstate pipelines for sales to local distribution companies and large industrial and commercial customers. The most significant provisions of Order No. 636 require that interstate pipelines provide transportation separate or “unbundled” from their sales service, and require that pipelines provide firm and interruptible transportation service on an open access basis that is equal for all natural gas suppliers. In many instances, the result of Order No. 636 and related initiatives has been to substantially reduce or eliminate the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. Another effect of regulatory restructuring is greater access to transportation on interstate pipelines. In some cases, producers and marketers have benefited from this availability. However, competition among suppliers has greatly increased and traditional long-term producer-pipeline contracts are rare. Furthermore, gathering facilities of interstate pipelines are no longer regulated by FERC, thus allowing gatherers to charge higher gathering rates. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently PDC has seen the increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in-gas, which could adversely affect cash flows from the affected area.

Additional proposals and proceedings that might affect the industry occur frequently in Congress, FERC, state commissions, state legislatures, and the courts. The industry historically has been very heavily regulated; therefore,

there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue. PDC cannot determine to what extent the partnership’s future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels.

Environmental Matters

The partnership’s operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and tougher environmental legislation and regulations is expected to continue. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs and reduced access to the industry in general, the partnership’s business and prospects could be adversely affected.

The partnership generates waste that may be subject to the Federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. The U.S. Environmental Protection Agency, or EPA, and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by the partnership’s operations that are currently exempt from treatment as “hazardous wastes” may, in the future, be designated as “hazardous wastes,” and therefore be subject to more rigorous and costly operating and disposal requirements.

The partnership currently owns properties that for many years have been used for the exploration and production of natural gas, NGLs and crude oil. Although the partnership believes that the partnership has utilized good operating and waste disposal practices, and when necessary, appropriate remediation techniques, prior owners and operators of these properties may not have utilized similar practices and techniques, and hydrocarbons or other wastes may have been disposed of or released on or under the properties that the partnership owns or on or under locations where such wastes have been taken for disposal. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, RCRA and analogous state laws, as well as state laws governing the management of natural gas and crude oil wastes. Under such laws, PDC could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination.

CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. As an owner and operator of natural gas and crude oil wells, the partnership may be liable pursuant to CERCLA and similar state laws.

The partnership’s operations may be subject to the Clean Air Act, or CAA, and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from the partnership’s operations. The EPA and states have been developing regulations to implement these requirements. The partnership has been required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. The State of Colorado has also implemented new air emission regulations in 2009, which affect the industry, including the partnership’s operations.

The Federal Clean Water Act, or CWA, and analogous state laws impose strict controls against the discharge of pollutants, including spills and leaks of crude oil and other substances. The CWA also regulates storm water run-off from natural gas and crude oil facilities and requires a storm water discharge permit for certain activities. Spill prevention, control, and countermeasure requirements of the CWA require appropriate containment terms and

similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak.

Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. Federal regulations require certain owners or operators of facilities that store or otherwise handle crude oil, including the partnership, to procure and implement Spill Prevention, Control and Counter-measures plans relating to the possible discharge of crude oil into surface waters. The Oil Pollution Act of 1990, or OPA, subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. The partnership is also subject to the CWA and analogous state laws relating to the control of water pollution, which laws provide varying civil and criminal penalties and liabilities for release of petroleum or its derivatives into surface waters or into the ground. Historically, the partnership has not experienced any significant crude oil discharge or crude oil spill problems.

In 2009, the State of Colorado’s Oil and Gas Conservation Commission implemented new broad-based environmental and wildlife protection regulations for the industry. These regulations will continue to increase the partnership’s costs. The partnership’s expenses relating to preserving the environment have risen over the past few years and are expected to continue to rise in 2011 and beyond. Environmental regulations have had no materially adverse effect on the partnership’s ability to operate to date, but no assurance can be given that environmental regulations or interpretations of such regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on the partnership’s business, financial condition or results of operations.

Industry Regulation

While the prices of natural gas, NGLs and crude oil are set by the market, other aspects of the partnership’s business and the industry in general are heavily regulated. The following summary discussion of the regulation of the United States industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental orders to which the partnership’s operations may be subject.

Legislative proposals and proceedings that might affect the petroleum and natural gas industries occur frequently in Congress, FERC, state commissions, state legislatures, and the courts. These proposals involve, among other things, imposition of direct or indirect price limitations on natural gas production, expansion of drilling opportunities in areas that would compete with partnership production, imposition of land use controls, landowners’ “rights” legislation, alternative fuel use requirements and tax incentives and other measures. The petroleum and natural gas industries historically have been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by FERC and Congress will continue. The partnership cannot determine to what extent its future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels. Illustrative of this trend are the regulations implemented in 2009 by the State of Colorado, which focus on the natural gas and crude oil industry. These multi-faceted regulations significantly enhance requirements regarding natural gas and crude oil permitting, environmental requirements and wildlife protection. Permitting delays and increased costs could result from these final regulations. Other potential or recently enacted laws and regulations affecting the partnership include the following:


	•	The U.S. Environmental Protection Agency, or EPA, has recently focused on citizen concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities. The EPA has held public meetings around the country on this issue that have been well publicized and well attended. This renewed focus could lead to additional federal and state laws and regulations affecting the partnership’s additional Codell formation development, fracturing and operations. Additional laws, regulations or other changes could significantly reduce the partnership’s future additional Codell formation development opportunities, increase the partnership’s costs of operations, and reduce the partnership’s distributable cash flows, in addition to undermining the demand for the natural gas and crude oil the partnership produces.

	•	Several bills in Congress, if passed, would establish a “cap and trade” system regarding greenhouse gas emissions. Companies would be assigned emission “allowances” under these bills which would decline each


		year. In addition, new EPA greenhouse gas monitoring and reporting regulations may affect the partnership and the third parties that process the partnership’s natural gas, NGLs and crude oil.


	•	New or increased severance taxes have been proposed in several states, which could adversely affect the existing operations in these states and the economic viability of future additional Codell formation development.

	•	In July 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). The Dodd-Frank Act regulates derivative transactions, including the partnership’s natural gas and crude oil hedging swaps. These swaps are broadly defined to include most of the partnership’s hedging instruments. The new law requires the issuance of new regulations and administrative procedures related to derivatives within one year. The effect of such future regulations on the partnership’s business is currently uncertain. In particular, note the following:

i. The Dodd-Frank Act may decrease PDC’s ability to enter into hedging transactions which would expose the partnership to additional risks related to commodity price volatility. Commodity price decreases could then have an immediate significant adverse affect on the partnership’s revenues and impair the partnership’s ability to have certainty with respect to a portion of the partnership’s distributable cash flows. A reduction in cash flows may lead to decreased investor cash distributions or fewer completed Codell formation development activities and therefore, decreased partnership’s proved reserves and future production.

ii. PDC expects that the cost to hedge will increase as a result of fewer counterparties in the market and the pass-through of increased counterparty costs. The partnership’s derivative counterparties may be subject to significant new capital, margin and business conduct requirements imposed as a result of the new legislation.

iii. The Dodd-Frank Act contemplates that most swaps will be required to be cleared through a registered clearing facility and traded on a designated exchange or swap execution facility. There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk. While the partnership may ultimately be eligible for such exceptions, the scope of these exceptions currently is somewhat uncertain, pending further definition through rulemaking proceedings.

iv. The above factors could also affect the pricing of derivatives and make it more difficult for PDC to enter into hedging transactions on behalf of the Partnership, on favorable terms.

Competitive Market Position

Competition is high among persons and companies involved in the exploration and production of natural gas and crude oil. Because there are thousands of natural gas and crude oil companies in the United States, the national supply of natural gas, including the Rockies Region which currently supplies approximately 22% of the U.S. natural gas production annually, is diversified. The partnership believes that the drilling and production capabilities and the experience of PDC’s management and professional staff generally enables the partnership to compete effectively. As a result of the well-publicized turmoil in the financial and commodity markets in late 2008, resultant industry slowdown throughout 2009 and PDC’s cost reduction initiatives, the partnership experienced overall reductions in its 2009 natural gas, NGLs and crude oil production costs. During 2010, PDC, as managing general partner of the partnership, has seen service costs steadily rise as oil prices and low cost shale opportunities have led to rig and completion crew redeployment. For more information on natural gas and crude oil pricing during 2010 and 2009, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Natural Gas and Crude Oil Sales.” The partnership believes that it can compete effectively in its area of operations. Nevertheless, the partnership’s results of operations and distributable cash flows could be materially adversely affected by the uncertainty in ascertaining the ultimate depth and duration of the current economic environment.

As a result of Federal Energy Regulatory Commission, or FERC, and Congressional deregulation of natural gas and crude oil prices in the past, prices are generally determined by competitive supply-and-demand market forces. The marketing of natural gas, NGLs and crude oil produced by the partnership is affected by a number of factors, some of which are beyond the partnership’s control and the exact effect of which cannot be accurately predicted. These factors include the volume and prices of crude oil imports, the availability and cost of adequate

natural gas and crude oil pipeline and other transportation facilities, the marketing of competitive fuels, such as coal, nuclear and renewable fuel 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 natural gas and crude oil in world markets combined with supply and demand balance within and across U.S. geographical regions may have caused significant variations in the prices of these traditional hydrocarbon products over recent years.

The partnership’s fields are crossed by natural gas pipelines belonging to DCP Midstream LP (“DCP”), Williams Production, RMT (“Williams”) and others. These companies have all traditionally purchased substantial portions of their natural gas supply from Colorado producers. The gas is sold at negotiated prices based upon a number of factors, including the quality of the gas, well pressure, estimated remaining reserves, prevailing supply conditions and any applicable price regulations promulgated by the FERC. FERC natural gas pipeline open-access initiatives implemented during the mid-1980’s to mid-1990’s, mandated that interstate gas pipeline companies separate their merchant activities from their transportation activities and thus release, on both a short and a long-term basis, available transmission system capacity. Thus, local distribution companies have taken an increasingly active role in acquiring their own natural gas supplies. Consequently, PDC believes interstate transmission pipelines and local distribution companies (utilities) are buying natural gas directly from natural gas producers and marketers, and retail unbundling efforts are causing many end-users to buy their own reserves. In general, the partnership has been and expects to continue to be able to produce and sell natural gas, NGLs and crude oil from the partnership’s wells at locally competitive prices.

The partnership’s secondary hydrocarbon product is oil. In contrast to U.S. natural gas pricing, which is determined more directly by North American supply-demand factors, crude oil pricing is subject to global supply-demand influences including the presence of the Organization of Petroleum Exporting Countries, or OPEC, whose members establish prices and production quotas for petroleum products of OPEC members from time to time. PDC is unable to predict what effect, if any, future OPEC actions will have on the quantity of, or prices received for, crude oil produced and sold from the partnership’s wells.

Colorado accounts for approximately 1% of the U.S.’s total annual domestic oil production and this production generally provides feedstock for Colorado’s two refineries located north of Denver and owned by Suncor Energy (USA) Inc. (“Suncor”). Rocky Mountain oil sales have traded at a discount compared to supplies available elsewhere in the U.S. due to an excess supply situation in the region that arose as a result of rising Canadian tar sand imports and lack of inter-regional export oil pipeline capacity to higher-oil demand regions. However, increased refining capacity near Denver has enabled local Colorado oil suppliers, including the partnership, to receive pricing advantage over supplies located in less densely-populated northern Rocky Region areas.

Reliance on Managing General Partner

General. As provided by the partnership agreement, PDC, as managing general partner of the partnership, has authority to manage the partnership’s activities through the D&O Agreement, utilizing its best efforts to carry out the business of the partnership in a prudent and business-like fashion. PDC has a fiduciary duty to exercise good faith and deal fairly with investors. PDC’s executive staff manages the affairs of the partnership, while technical geosciences and petroleum engineering staff oversee the well drilling, completions, recompletions, and operations. PDC’s administrative staff controls the partnership’s finances and makes distributions, apportions costs and revenues among wells and prepares partnership reports, financial statements and filings presented to investors, tax agencies and the SEC, as required.

Provisions of the D&O Agreement. Under the terms of the D&O Agreement, the partnership has authorized and extended to PDC the authority to manage the production operations of the natural gas and crude oil wells in which the partnership owns an interest, including the initial drilling, testing, completion, and equipping of wells; subsequent additional Codell formation development, where economical, and ultimate evaluation for abandonment. Further, the partnership has the right to take in-kind and separately dispose of its share of all natural gas, NGLs and crude oil produced from the partnership’s wells. The partnership designated PDC as its natural gas, NGLs and crude oil production marketing agent and authorized PDC to enter into and bind the partnership, under those agreements PDC deems in the best interest of the partnership, in the sale of the partnership’s natural gas, NGLs and crude oil. Generally, PDC has limited liability to the partnership for losses sustained or liabilities incurred, except as may

result from the operator’s gross or willful negligence or misconduct. PDC may subcontract certain functions as operator for partnership wells but retains responsibility for work performed by subcontractors. The D&O Agreement remains in force as long as any well or wells produce, or are capable of economic production, and for an additional period of 180 days from cessation of all production or until PDC is replaced as managing general partner of the partnership as provided for in the D&O Agreement.

To the extent the partnership has less than a 100% working interest in a well, partnership obligations and liabilities are limited to its proportionate working interest share and thus, the partnership paid only its proportionate share of total lease and development costs, pays only the partnership’s proportionate share of operating costs, and receives its proportionate share of production subject only to royalties and overriding royalties.

Under the D&O Agreement, PDC provides all necessary labor, vehicles, supervision, management, accounting, and overhead services for normal production operations and may deduct from partnership revenues a fixed monthly charge for these services. The charge for these operations and field supervision fees (referred to as “well tending fees”) for each producing well is based on competitive industry field rates which vary based on areas of operation. The well tending fees and administration fees may be adjusted annually to an amount equal to the rates initially established by the D&O Agreement multiplied by the then current average of the Oil and Gas Extraction Index and the Professional and Technical Services Index, 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. This average is commonly referred to as the Accounting Procedure Wage Index Adjustment which is published annually by the Council of Petroleum Accountants Societies, or COPAS. These rates are reflective of similar costs incurred by comparable operators in the production field. PDC, in certain circumstances, has and may in the future, provide equipment or supplies, perform salt water disposal services or other services for the partnership at the lesser of cost or competitive prices in the area of operations.

Operating Hazards and Insurance. The partnership’s production operations include a variety of operating risks, including but not limited to fire, explosions, blowouts, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as gas leaks, ruptures and discharges of natural gas. The occurrence of any of these could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. The partnership’s gathering and distribution operations are subject to the many hazards inherent in the industry. These hazards include damage to wells, pipelines and other related equipment, damage to property caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

Any significant problems related to the partnership’s facilities could adversely affect the partnership’s ability to conduct operations. In accordance with customary industry practice, the partnership maintains insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant event not fully insured against could materially adversely affect the partnership’s operations and financial condition. The partnership cannot predict whether insurance will continue to be available at premium levels that justify purchase or whether insurance will be available at all. Furthermore, the partnership is not insured against economic losses resulting from damage or destruction to third party property, such as the Rockies Express pipeline; such an event could result in significantly lower regional prices or the partnership’s inability to deliver natural gas.

PDC, in its capacity as operator, has purchased various insurance policies, including worker’s compensation, operator’s bodily injury liability and property damage liability insurance, employer’s liability insurance, automobile public liability insurance and operator’s umbrella liability insurance and intends to maintain these policies subject to PDC’s analysis of their premium costs, coverage and other factors. During drilling operations, PDC as managing general partner of the partnership, maintained public liability insurance of not less than $10 million; however, PDC may at its sole discretion in other situations, increase or decrease policy limits, change types of insurance and name PDC and the partnership, individually or together, parties to the insurance as deemed appropriate under the circumstances, which may vary materially. As operator of the partnership’s wells, PDC requires its subcontractors to carry liability insurance coverage with respect to the subcontractors’ activities. PDC’s

management, in its capacity as managing general partner of the partnership, believes that in accordance with customary industry practice, adequate insurance, including insurance by PDC’s subcontractors, has been provided to the partnership with coverage sufficient to protect the investors against the foreseeable risks of operation, drilling, additional Codell formation development and reworks and ongoing productions operations. However, there can be no assurance that this insurance will be adequate to cover all losses or exposure for liability and thus, the occurrence of a significant event not fully insured against, could materially adversely affect partnership operations and financial condition. Furthermore, the partnership is not insured against economic losses resulting from damage or destruction to third party property, such as the Rockies Express pipeline; such an event could result in significantly lower regional prices or the partnership’s inability to deliver natural gas. As of the date of this filing, PDC has no knowledge that such events have occurred.

Unit Repurchase Program

Investors may request that PDC repurchase units at any time beginning with the third anniversary of the first cash distribution of the partnership. The repurchase price is set at a minimum of four times the most recent twelve months of cash distributions from production. In any calendar year, PDC is conditionally obligated to purchase investor’s units aggregating to 10% of the initial subscriptions if requested by an individual investor, subject to PDC’s financial ability to do so and upon receipt of opinions of counsel that the repurchase will not cause the partnership to be treated as a “publicly traded partnership” or result in the termination of the partnership for federal income tax purposes. If accepted, repurchase requests are fulfilled by PDC on a first-come, first-serve basis.

In addition to the above repurchase program, individual investors periodically offered and PDC repurchased units on a negotiated basis before the third anniversary of the date of the first cash distribution. As of April 7, 2011, PDC suspended the opportunity for an individual investors to request that PDC repurchase their respective limited partnership units under the terms of the program, pending the outcome of the proposed merger agreement.

Customers

PDC markets the natural gas, NGLs and crude oil from partnership wells in Colorado subject to market sensitive contracts, the price of which increases or decreases with market forces beyond control of the partnership. Currently, PDC sells partnership natural gas in the Piceance Basin to Williams Production RMT (“Williams”), which has an extensive gathering and transportation system in this Basin. In the Wattenberg Field, the natural gas and NGLs are sold primarily to DCP Midstream LP (“DCP”), which gathers and processes the gas and liquefiable hydrocarbons produced. Natural gas and NGLs produced in Colorado may be impacted by changes in market prices on a national level, as well as changes in the market for natural gas within the Rocky Mountain Region. Sales of natural gas and NGLs from the partnership’s wells to DCP and Williams are made on the spot market via open-access transportation arrangements through Williams or other pipelines and may be impacted by capacity interruptions on pipelines transporting natural gas out of the region.

The partnership’s crude oil production is sold, at or near the partnership’s wells under short-term purchase contracts at prices and in accordance with arrangements that are customary in the oil industry, primarily as feedstock for refineries currently owned by Suncor, which are located north of Denver, Colorado. Oil prices fluctuate not only with the general market for oil as may be indicated by changes in the New York Mercantile Exchange, or NYMEX, but also due to changes in light-heavy crude oil supply and product demand-mix applicable to specific refining regions.

Number of total and full-time employees

The partnership has no employees and relies on PDC to manage the partnership’s business. PDC’s officers, directors and employees receive direct remuneration, compensation or reimbursement solely from PDC, and not the partnership, with respect to their services rendered in their capacity to act on behalf of PDC, as managing general partner of the partnership.

Legal Proceedings

Neither the partnership nor PDC, in its capacity as the managing general partner of the partnership, are party to any pending legal proceeding that PDC believes would have a materially adverse effect on the partnership’s business, financial condition, results of operations or liquidity.

MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis, as well as other sections in this proxy statement, should be read in conjunction with the partnership’s accompanying financial statements and related notes to the financial statements included as Appendix E to this proxy statement. Further, the partnership encourages the reader to revisit the Cautionary Statement Regarding Forward-Looking Statements on page 50 of this proxy statement.

Partnership Overview

The partnership engages in the development, production and sale of natural gas, NGLs and crude oil. The Partnership began natural gas and crude oil operations in December 2002 and operates 35 gross (31.4 net) productive wells located in the Rocky Mountain Region in the state of Colorado. In addition, one (0.9 net) well in the Wattenberg Field is temporarily not in production at June 30, 2011 due to equipment problems. PDC, as managing general partner of the partnership, markets the partnership’s natural gas and crude oil production to commercial end users, interstate or intrastate pipelines, local utilities or oil companies, primarily under market sensitive contracts in which the price of natural gas, NGLs and crude oil sold varies as a result of market forces. PDC does not charge an additional fee for the marketing of the natural gas, NGLs and crude oil because these services are covered by the monthly well operating charge. PDC, on behalf of the partnership in accordance with the D&O Agreement, is authorized to enter into multi-year fixed price contracts or utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the commodity price variability for particular periods of time. Seasonal factors, such as effects of weather on prices received and costs incurred, and availability of pipeline capacity, owned by PDC or other third parties, may impact the partnership’s results. In addition, both sales volumes and prices tend to be affected by demand factors with a seasonal component.

Additional Codell Formation Development Plan

PDC, as managing general partner of the partnership, has prepared a plan, which we refer to as the additional Codell formation development plan, for the partnership’s Wattenberg Field wells which may provide for additional reserve development of natural gas, NGLs and crude oil production. The additional Codell formation development plan consists of the partnership’s refracturing of wells currently producing in the Codell formation and the recompletion of wells, currently producing in the deeper J-Sand formation, in the shallower Codell formation production zone. Under the additional Codell formation development plan, the partnership plans to initiate additional development activities during 2012. Refracturing, or “refracing,” activities consist of a second hydraulic fracturing treatment in a current production zone, while recompletion activities consist of an initial hydraulic fracturing treatment in a new production zone, all within an existing well bore.

Additional Codell formation development of Wattenberg Field wells, which may provide for additional reserve development and production, generally occurs five to ten years after initial well drilling so that well resources are optimally utilized. This additional Codell formation development would be expected to occur based on a favorable general economic environment and commodity price structure. PDC, as managing general partner of the partnership, has the authority to determine whether to refracture or recomplete the individual wells and to determine the timing of any additional Codell formation development activity. The timing of the refracturing or recompletion can be affected by the desire to optimize the economic return by additional development of the wells when commodity prices are at levels to obtain the highest rate of return to the partnership. On average, the production resulting from PDC’s Codell refracturings or recompletions have been at modeled economics; however, all refracturings or recompletions have not been economically successful and similar future refracturing or recompletion activities may not be economically successful. If the additional Codell formation development work is performed, PDC will charge the partnership for the direct costs of refracturing or recompletion, and the investors and PDC will each pay their proportionate share of costs based on the ownership sharing ratios of the partnership from funds retained by PDC from cash available for distributions. PDC considers the cash available for distributions to be the partnership’s net cash flows provided by operating activities less any net cash used in capital activities.

During the fourth quarter 2010, PDC began a program for its affiliated partnerships to begin accumulating cash from cash flows from operating activities to pay for future refracturing and recompletion costs. This program will

materially reduce, up to 100%, cash available for distributions of the partnerships for a period of time not to exceed five years. The partnership has not begun to withhold funds for this additional Codell formation development as the partnership has outstanding payables to PDC.

Current estimated costs for these well refracturings or recompletions are between $175,000 and $240,000 per activity. As of June 30, 2011, this partnership had scheduled to complete 32 additional Codell formation development opportunities. Total withholding for these activities from the partnership’s cash available for distributions is estimated to be between $5.6 million and $7.7 million. PDC will continually evaluate the timing of commencing these additional Codell formation development activities based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the additional well development. As of July 31, 2011, no funds have been withheld from the partnership distributions for this recompletion and refracturing.

If any or all of the partnership’s Wattenberg wells are not refractured or recompleted, the partnership will experience a reduction in proved reserves currently assigned to these wells. Both the number and timing of the additional Codell formation development activities will be based on the availability of cash withheld from partnership distributions. PDC believes that, based on projected refracturing and recompletion costs and projected cash withholding, all scheduled partnership additional Codell formation development activity will be completed within a five year period. Any funds not used for refracturing, recompletion or other operational needs will be distributed to the PDC and the investors based on their proportional ownership interest.

Implementation of the additional Codell formation development plan will reduce or eliminate partnership distributions to PDC and the investors while the work is being conducted and paid for through the partnership funds. Depending upon the level of withholding and the results of operations, it is possible that PDC and the investors could have taxable income from the partnership without any corresponding distributions in future years. Investors are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the additional Codell formation development plan. The above discussion is not intended as a substitute for careful tax planning, and investors should depend upon the advice of their own tax advisors concerning the effects of the additional Codell formation development plan.

First Six Months 2011 Partnership Operating Results Overview

Natural gas, NGLs and crude oil sales decreased 5% or $36,000 for the first six months of 2011 compared to the first six months of 2010, while sales volumes declined 6% period-to-period. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.82 for the current year period compared to $5.75 for the same period a year ago. Realized derivative gains from natural gas and crude oil sales contributed an additional $0.25 per Mcfe or $29,000 to the first six months of 2011 total revenues compared to an additional $1.65 or $210,000 to the first six months of 2010. Comparatively, the total realized price per Mcfe, consisting of the average sales price and realized derivative gains, decreased to $6.07 for the current year six months from $7.40 for the same prior year period.

Natural gas, NGLs and crude oil production costs decreased by approximately $460,000 during the six months ended June 30, 2011 compared to the same period in the prior year due to the effect of decreased environmental remediation expenses. Direct costs — general and administrative increased by approximately $229,000 during the 2011 six month period due to increased fees for professional services.

2010 and 2009 Partnership Operating Results Overview

Natural gas, NGLs and crude oil sales increased 8% or $0.1 million for the 2010 annual period compared to 2009, even though production volumes decreased 14% period-to-period. This revenue increase was supported primarily by the improved commodity price environment. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.46 during 2010 compared to $4.33 for 2009. Comparatively, the total per Mcfe price realized, consisting of the average sales price and realized derivative gains, decreased to $6.66 during 2010 from $7.69 during 2009. This decrease was primarily due to realized derivative gains from natural gas and crude oil sales contributing only $1.20 per Mcfe or $0.3 million to the 2010 total revenues as compared to $3.36 per Mcfe or $1.0 million to 2009 total revenues. The partnership’s 2010 revenues were favorably impacted by unrealized

derivative gains on natural gas and crude oil sales of $0.6 million in 2010 as compared to unrealized losses of $1.5 million in 2009.

The partnership’s combined natural gas and crude oil production expenses and direct costs-administrative and general, increased by $0.9 million during 2010. Higher production expenditures were primarily due to environmental remediation activities during 2010 while higher administrative and general expenses were due to higher fees for professional services.

The partnership recorded an impairment loss of $0.6 million for the year ended December 31, 2010. The impairment loss resulted from the downward revision to the future net cash flows of production activities in the Grand Valley Field in Colorado.

Reporting on NGLs in 2010

As the partnership embarks on the Additional Codell Formation Development Plan, PDC believes that the NGLs will be an increased percentage of the partnership’s total revenues and production volumes in future years. Additionally, as a result of a computer system upgrade during the second half of 2009, PDC was able to accumulate the partnership’s NGLs sales revenues and production volumes for 2010. Prior to the system upgrade, the partnership’s NGLs sales revenues and production volumes were included in the natural gas sales revenues and production volume statistical information. The NGLs are extracted by third-party purchasers from the partnership’s natural gas production, after delivery. To provide additional information to the reader, the partnership has shown all of the NGLs revenue and production volume statistical data separately for 2010. For comparability when discussing 2010 results with 2009, the partnership has added the 2010 NGLs sales revenue and natural gas equivalent production volumes with the relevant 2010 natural gas activity data and compared it to the 2009 natural gas results. Reporting the partnership’s information in this fashion, gives comparability to readers when discussing the partnership’s year to year results and provides more detailed information which may be beneficial for understanding the partnership’s current business. Starting in the first quarter of 2011, the partnership’s revenues and production volumes of natural gas, NGLs and crude oil were presented in a fashion comparable to the 2010 information contained in this proxy statement.

Results of Operations

The following table presents selected information regarding the partnership’s results of operations. Prior to 2010, NGLs were included in natural gas, which impacts the comparability of natural gas production, natural gas sales, and natural gas average sales price for 2010 to 2009. However, total Mcfe production, total sales and Mcfe average price is comparable.


	Three Months Ended									Six Months Ended
	June 30,									June 30,								Year Ended December 31,
	2011			2010			Change			2011			2010		Change			2010		2009		Change

Number of producing wells (end of period)		35			35			—			35			35		—			35		35		—
Production⁽¹⁾
Natural gas (Mcf)		43,348			45,992			(6	)%		86,727			92,119		(6	)%		185,860		236,357		(21	)%
NGLs (Bbl)		947			835			13	%		1,787			1,712		4	%		3,418		—		*
Crude oil (Bbl)		1,510			1,982			(24	)%		3,550			4,035		(12	)%		7,935		9,929		(20	)%
Natural gas equivalents (Mcfe)⁽²⁾		58,090			62,894			(8	)%		118,749			126,601		(6	)%		253,978		295,931		(14	)%
Average Mcfe per day		638			691			(8	)%		656			699		(6	)%		696		811		(14	)%
Natural Gas, NGLs and Crude Oil Sales⁽⁴⁾
Natural gas	$	138,549		$	147,940			(6	)%	$	280,636		$	365,021		(23	)%	$	655,761	$	770,666		(15	)%
NGLs		46,463			31,827			46	%		91,934			70,557		30	%		149,203				*
Crude oil		142,122			143,335			(1	)%		318,403			291,858		9	%		582,060		511,006		14	%

Total natural gas, NGLs and crude oil sales	$	327,134		$	323,102			1	%	$	690,973		$	727,436		(5	)%	$	1,387,024	$	1,281,672		8	%

Realized Gain (Loss) on Derivatives, net⁽⁴⁾
Natural gas	$	41,119		$	(821	)		*		$	81,436		$	158,494		(49	)%	$	210,015	$	770,291		(73	)%
Crude Oil		(30,345	)		26,616			(214	)%		(52,102	)		51,520		(201	)%		95,618		224,415		(57	)%

Total realized gain on derivatives, net	$	10,774		$	25,795			(58	)%	$	29,334		$	210,014		(86	)%	$	305,633	$	994,706		(69	)%

Average Selling Price (excluding realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	3.20		$	3.22			(1	)%	$	3.24		$	3.96		(18	)%	$	3.53	$	3.26		8	%
NGLs (per Bbl)		49.06			38.12			29	%		51.45			41.21		25	%		43.65		—		*
Crude Oil (per Bbl)		94.12			72.32			30	%		89.69			72.33		24	%		73.35		51.47		43	%
Natural gas equivalents (per Mcfe)		5.63			5.14			10	%		5.82			5.75		1	%		5.46		4.33		26	%
Average Selling Price (including realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	4.14		$	3.20			30	%	$	4.17		$	5.68		(27	)%	$	4.66	$	6.52		(29	)%
NGLs (per Bbl)		49.06			38.12			29	%		51.45			41.21		25	%		43.65		—		*
Crude Oil (per Bbl)		74.02			85.75			(14	)%		75.01			85.10		(12	)%		85.40		74.07		15	%
Natural gas equivalents (per Mcfe)		5.82			5.55			5	%		6.07			7.40		(18	)%		6.66		7.69		(13	)%
Average Cost per Mcfe
Natural gas, NGLs and crude oil production cost⁽³⁾	$	2.09		$	5.14			(59	)%	$	2.31		$	5.80		(60	)%	$	4.38	$	2.22		97	%
Depreciation, depletion and amortization	$	3.38		$	4.38			(23	)%	$	3.41		$	4.40		(22	)%		4.55		3.87		18	%
Operating Costs and Expenses:
Direct costs — general and administrative	$	40,013		$	4,917			*		$	235,970		$	6,915		*		$	474,479	$	35,465		*
Depreciation, depletion and amortization	$	196,534		$	275,553			(29	)%	$	405,322		$	557,099		(27	)%	$	1,155,598	$	1,144,024		1	%
Loss on impairment of natural gas and crude oil production		—			—			*			—			—		*		$	648,608	$	—		*
Cash Distributions	$	19,768		$	173,201			(89	)%	$	40,322		$	639,462		(94	)%	$	671,912	$	2,330,581		(71	)%


*		Percentage change not meaningful, equal to or greater than 250% or not calculable. Amounts may not calculate due to rounding.

(1)		Production is net and determined by multiplying the gross production volume of properties in which the partnership has an interest by the average percentage of the leasehold or other property interest the partnership owns.

(2)		A ratio of energy content of natural gas and crude oil (six Mcf of natural gas equals one Bbl of crude oil or NGL) was used to obtain a conversion factor to convert NGLs and crude oil production into equivalent Mcf of natural gas.

(3)		Production costs represent natural gas, NGLs and crude oil operating expenses which include production taxes.


(4)		This data has been derived from the partnership’s audited financial statements as of December 31, 2010 and 2009 and for the years then ended and unaudited financial statements as of June 30, 2011 and 2010 and for the periods then ended, which are included as Appendix E to this proxy statement.

Natural Gas, NGLs and Crude Oil Sales

Six months ended June 30, 2011 as compared to six months ended June 30, 2010

For the six months ended June 30, 2011 compared to the same period in 2010, natural gas, NGLs and crude oil sales, on an energy equivalency-basis, decreased 6% due to normal production declines for this stage in the wells’ production life cycle.

The approximately $36,000, or 5% decrease in sales for the 2011 six month period as compared to the prior year period, was primarily a reflection of sales volume decreases of 6% partially offset by an increase in sales prices of 1%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.82 for the current year six month period compared to $5.75 for the same period a year ago.

Natural gas revenue decreased by 23% while NGLs and crude oil revenues increased by 30% and 9%, respectively. The partnership’s natural gas revenue decrease resulted from lower partnership natural gas production volumes of 6% and from decreased commodity prices per Mcf of 18%. The NGLs revenue increased due to increased commodity prices per Bbl of 25%, and an increase of 4% in NGLs production volumes. The crude oil revenue increase is due primarily to the rise in commodity prices per Bbl of 24%, partially offset by sales volume decreases of 12%, during the current six month period.

Three months ended June 30, 2011 as compared to three months ended June 30, 2010

For the three months ended June 30, 2011 compared to the same period in 2010, natural gas, NGLs and crude oil sales, on an energy equivalency-basis, decreased 8% due to normal production declines for this stage in the wells’ production life cycle.

The approximately $4,000, or 1%, increase in sales for the 2011 three month period as compared to the prior year period was primarily a reflection an increase in sales prices of 10%, partially offset by of lower sales volumes of 8%. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $5.63 for the current year three month period compared to $5.14 for the same period a year ago.

NGLs revenue increased by 46% and was partially offset by decreases in natural gas and crude oil revenues of 6% and 1%, respectively. The partnership’s natural gas revenue decrease resulted from lower partnership natural gas production volumes of 6%, and decreased commodity prices per Mcf, of 1%. The increase in NGLs revenue was due to increased commodity prices per Bbl of 29%, and an increase of 13% in NGLs production volumes. The crude oil revenue decrease is due primarily to sales volume decreases of 24%, partially offset by the rise in commodity prices per Bbl of 30% during the current three month period.

Year ended December 31, 2010 as compared to year ended December 31, 2009.

Changes in Natural Gas, NGLs and Crude Oil Production Volumes. For the 2010 annual period compared to the 2009 annual period, natural gas, NGLs and crude oil production, on an energy equivalency-basis, decreased 14% due to normal production declines for this stage in the wells’ production life cycle, production reductions that resulted from well equipment or operational issues at some Wattenberg Field wells and lower Grand Valley well performance due to well optimization efforts.

Changes in Natural Gas and NGLs Sales. During 2010, the partnership began separate reporting of NGL sales, which were previously classified and reported as a component of natural gas sales revenues. Combined 2010 natural gas and NGL sales were $34,000, or 4% higher than comparably reported 2009 natural gas sales revenues. Combined production from natural gas and NGLs were 206,368 Mcfe in 2010 compared to 236,357 Mcfe in 2009. This 29,989 Mcfe or 13% reduction in production was more than offset by the higher average selling price for these commodities of $3.90 per Mcfe in 2010 compared to $3.26 in 2009. This $0.64 per Mcfe increase represents a 20% overall price increase from the prior year.

Changes in Crude Oil Sales. The $0.1 million, or 14%, increase in oil sales for the 2010 annual period as compared to the 2009 annual period, was primarily the reflection of a higher average sales price per Bbl of 43%, which was partially offset by the production volume decrease of 20%. The average sales price per Bbl, excluding the

impact of realized derivative gains, was $73.35 for the current year annual period compared to $51.47 for the same period a year ago.

Natural Gas, NGLs and Crude Oil Pricing. The partnership’s results of operations depend upon many factors, particularly the price of natural gas, NGLs and crude oil and on PDC’s ability to market the partnership’s production effectively. Natural gas, NGLs and crude oil prices are among the most volatile of all commodity prices. These price variations have a material impact on the partnership’s financial results. Natural gas and NGLs prices vary by region and locality, depending upon the distance to markets, and the supply and demand relationships in that region or locality and availability of sufficient pipeline capacity. This can be especially true in the Rocky Mountain Region. The combination of increased drilling activity and the lack of local markets have resulted in local market oversupply situations from time to time. Like most producers in the region, the partnership relies on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities and transportation capacity beyond the partnership’s control. Crude oil pricing is driven predominantly by the physical market, supply and demand, the financial markets and politics.

The price at which PDC markets the natural gas produced in the Rocky Mountain Region by the partnership is based on a variety of prices, which primarily includes natural gas sold at Colorado Interstate Gas, or CIG, prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby regional prices. The CIG Index, and other indices for production delivered to other Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is primarily New York Mercantile Exchange, or NYMEX, based, because of the lack of interstate transmission capacity which moved Rocky Mountain natural gas production to Northeastern U.S. industrial and heating markets. This negative differential has narrowed in the last few years and is lower than historical variances. The negative differential between NYMEX and CIG averaged $0.47 and $0.92 for 2010 and 2009, respectively.

Commodity Price Risk Management, Net

The partnership uses various derivative instruments to manage fluctuations in natural gas and crude oil prices. The partnership has in place a variety of floors, collars, fixed-price swaps and basis swaps on a portion of the partnership’s estimated natural gas and crude oil production. Because the partnership sells its natural gas and crude oil at similar prices to the indices inherent in the partnership’s derivative instruments, the partnership ultimately realizes a price related to its collars of no less than the floor and no more than the ceiling and, for the partnership’s commodity swaps, the partnership ultimately realizes the fixed price related to its swaps.

Commodity price risk management, net, includes realized gains and losses and unrealized mark-to-market changes in the fair value of the derivative instruments related to the partnership’s natural gas and crude oil

production. The following table presents the realized and unrealized derivative gains and losses included in commodity price risk management gain (loss), net.


	Three Months Ended						Six Months Ended
	June 30,						June 30,					Year Ended December 31,
	2011			2010			2011			2010		2010			2009
	(Unaudited)						(Unaudited)					(Audited)

Commodity price risk management, net
Realized gain (loss)
Natural Gas	$	41,119		$	(821	)	$	81,436		$	158,494	$	210,015		$	770,291
Crude Oil		(30,345	)		26,616			(52,102	)		51,520		95,618			224,415

Total realized gain, net		10,774			25,795			29,334			210,014		305,633			994,706

Unrealized gain (loss)
Reclassification of realized gain included in prior periods unrealized		(9,354	)		(18,549	)		(36,341	)		(120,572		(33,777	)		(858,148	)
Unrealized (loss) gain for the period		96,732			148,618			49,753			528,447		589,493			(632,967	)

Total unrealized (loss) gain, net		87,378			130,069			13,412			407,875		555,716			(1,491,115	)

Commodity price risk management gain (loss), net	$	98,152		$	155,864		$	42,746		$	617,889	$	861,349		$	(496,409	)

Six months ended June 30, 2011 as compared to six months ended June 30, 2010

Realized gains recognized in the six months ended June 30, 2011 are primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of the partnership’s natural gas derivative positions. Realized gains on natural gas settlements were approximately $186,000 for the six months ended June 30, 2011. These gains were offset in part by an approximate $105,000 loss on the partnership’s CIG basis protection swaps as the negative basis differential between NYMEX and Colorado Interstate Gas (“CIG”) was narrower than the strike price of the basis positions. The partnership also realized an approximate $52,000 loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price. Unrealized gains during the six months ended June 30, 2011 are primarily related to the shifts in the forward curves and their impact on the fair value of the partnership’s open positions. The shifts downward in the natural gas curves resulted in an unrealized gain of approximately $91,000 which was partially offset by unrealized losses of approximately $36,000 on the partnership’s CIG basis protection swaps as the forward basis differential between the NYMEX and CIG had continued to narrow. Additionally, the shifts upward in the crude oil curves resulted in an unrealized loss of approximately $5,000.

The realized derivative gains for the 2010 six month period were approximately $210,000. These realized gains were primarily a result of lower natural gas and oil spot prices at settlement compared to the respective strike price, offset in part by realized losses due to the basis differential between NYMEX and CIG being narrower than the strike price of the derivative position. For the six month period, realized gains related to natural gas and oil derivatives were approximately $210,000 and $52,000, respectively, and realized losses on the partnership’s CIG basis protection swaps were approximately $52,000. Unrealized gains for the six month period were approximately $528,000 due primarily to a downward shift in the natural gas and oil forward curves. Unrealized gains on the partnership’s natural gas and oil positions for the period were approximately $478,000 and $50,000, respectively.

Three months ended June 30, 2011 as compared to three months ended June 30, 2010

Realized gains recognized in the three months ended June 30, 2011 are primarily the result of lower natural gas spot prices at settlement compared to the respective strike price of the partnership’s natural gas derivative positions. Realized gains on natural gas settlements were approximately $110,000 for the three months ended June 30, 2011. These gains were offset in part by an approximate $69,000 loss on the partnership’s CIG basis protection swaps as

the negative basis differential between NYMEX and CIG was narrower than the strike price of the basis positions. The partnership also realized an approximate $30,000 loss on its crude oil positions due to higher spot prices at settlement compared to the respective strike price. Unrealized gains during the three months ended June 30, 2011 are primarily related to the shifts in the forward curves and their impact on the fair value of the partnership’s open positions. The shift downward in the crude oil curve resulted in an unrealized gain of approximately $21,000 during the three months ended June 30, 2011. Likewise, the shifts downward in the natural gas and basis curves resulted in a total unrealized gain of approximately $76,000.

The realized derivative gains for the 2010 second quarter were approximately $26,000. These realized gains are a result of lower natural gas and oil spot prices at settlement compared to the respective strike price, offset in part by realized losses due to the basis differential between NYMEX and CIG being narrower than the strike price of the derivative position. For the quarter, realized gains related to natural gas and oil derivatives were approximately $78,000 and realized losses on the partnership’s CIG basis swaps were approximately $52,000. For the 2010 second quarter, the unrealized gains were primarily related to the oil positions, as the forward strip price shifted downward during the quarter, and the widening of the NYMEX-CIG basis differential. Unrealized gains on the partnership’s oil positions and CIG basis protection swaps for the 2010 second quarter were approximately $54,000 and $82,000, respectively. Additionally, the shifts downward in the natural gas curves resulted in an unrealized gain of approximately $13,000.

Year ended December 31, 2010 as compared to year ended December 31, 2009.

Realized gains recognized in 2010 and 2009 are a result of lower natural gas and crude oil spot prices at settlement compared to the respective strike price, offset in part by the negative basis differential between NYMEX and CIG being narrower than the strike price of the partnership’s derivative position. During 2010, the partnership recorded unrealized gains of $0.7 million on the partnership’s natural gas and crude oil positions that were partially offset by unrealized losses of $0.1 million on its CIG basis swaps as the forward basis differential between NYMEX and CIG had continued to narrow from the prior year.

During 2009, the partnership recorded unrealized losses on its CIG basis swaps as the forward basis differential between NYMEX and CIG had continued to narrow from the prior year along with unrealized losses on the partnership’s crude oil positions, offset by unrealized gains on the partnership’s natural gas positions.

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The following table presents the partnership’s derivative positions in effect as of June 30, 2011.


							Fixed-Price Swaps				CIG Basis Protection Swaps
	Collars								Weighted				Weighted			Fair
	Quantity		Weighted Average						Average		Quantity		Average			Value at
	(Gas-		Contract Price				Quantity		Contract		(Gas-		Contract			June 30,
Commodity/Index	MMBtu⁽¹⁾)		Floors		Ceilings		(Gas-MMBtu⁽¹⁾ Oil-Bbls)		Price		MMBtu⁽¹⁾)		Price			2011⁽²⁾

Natural Gas
NYMEX
07/01 — 09/30/2011		—	$	—	$	—		43,985	$	6.73		43,985	$	(1.88	)	$	35,909
10/01 — 12/31/2011		—		—		—		42,939		6.78		42,939		(1.88	)		27,940
01/01 — 03/31/2012		2,527		6.00		8.27		39,054		6.98		41,581		(1.88	)		23,770
04/01 — 06/30/2012		1,368		6.00		8.27		39,537		6.98		40,905		(1.88	)		33,575
07/01 — 12/31/2012		3,869		6.00		8.27		76,252		6.98		80,121		(1.88	)		46,941
2013		—		—		—		149,877		7.12		149,877		(1.88	)		78,667

Total Natural Gas		7,764						391,644				399,408					246,802

Crude Oil
NYMEX
07/01 — 09/30/2011		—		—		—		968		70.75		—		—			(23,701	)
10/01 — 12/31/2011		—		—		—		992		70.75		—		—			(25,697	)

Total Crude Oil		—						1,960				—					(49,398	)

Total Natural Gas and Crude Oil																$	197,404


(1)		A standard unit of measure for natural gas (one MMBtu equals one Mcf)


(2)		Approximately 1% of the fair value of the partnership’s derivative assets and all of the partnership’s derivative liabilities were measured using significant unobservable inputs (Level 3); see Note 4, Fair Value of Financial Instruments, to the accompanying unaudited condensed financial statements included in this report.

Natural Gas, NGLs and Crude Oil Production Costs

Natural gas, NGLs and crude oil production costs include production taxes and transportation costs which vary with revenues and production, well operating costs charged on a per well basis and other direct costs incurred in the production process. As production declines, fixed costs increase as a percentage of total costs resulting in production costs per unit increases. Typically, as production is expected to continue to decline, production costs per unit can be expected to increase in the future until such time as the partnership successfully recompletes the Wattenberg Field wells.

Generally, natural gas, NGLs and crude oil production costs vary with changes in total natural gas, NGLs and crude oil sales and production volumes. Production taxes are estimates by PDC based on tax rates determined using published information. These estimates are subject to revision based on actual amounts determined during future filings by PDC with the taxing authorities. Production taxes vary directly with total natural gas, NGLs and crude oil sales. Transportation costs vary directly with production volumes. Fixed monthly well operating costs increase on a per unit basis as production decreases per the historical decline curve. In addition, general oil field services and all other costs vary and can fluctuate based on services required but are expected to increase as wells age and require more extensive repair and maintenance. These costs include water hauling and disposal, equipment repairs and maintenance, snow removal and service rig workovers.

Changes in natural gas, NGLs and crude oil production expenses.

Six months ended June 30, 2011 as compared to six months ended June 30, 2010

Production and operating costs per Mcfe decreased to $2.31 during the current period compared to $5.80 for the prior year period due to the effect of decreased environmental remediation costs. The overall decrease in

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production and operating costs of approximately $460,000 is due to environmental remediation projects accrued for the prior year at six of the partnership’s Grand Valley Field wells and one of the Wattenberg Field wells; there were no environmental remediation expenses during the six months ended June 30, 2011.

Three months ended June 30, 2011 as compared to three months ended June 30, 2010

Production and operating costs per Mcfe decreased to $2.09 during the current period compared to $5.14 for the prior year period due to the effect of decreased environmental remediation charges. The overall decrease in production and operating costs of approximately $202,000 is due to environmental remediation projects accrued for the prior year at four of the partnership’s Grand Valley Field wells; there were no environmental remediation expenses during the three months ended June 30, 2011.

Year ended December 31, 2010 as compared to year ended December 31, 2009. Production and operating costs increased by approximately $0.5 million for 2010 compared to 2009 due primarily to nonrecurring environmental remediation expenses of $0.5 million, which includes a December 31, 2010 accrual of $31,000. Production costs were also higher as a result of the increase in the per well operations fee charged by PDC, as managing general partner of the partnership, consistent with the terms of the D&O Agreement. These production expense increases were partially offset by volume-associated reductions in production taxes, natural gas transportation and lease operating expenses due to the production volume declines. Production and operating costs per Mcfe were $4.38 during 2010 compared to $2.22 during 2009.

Direct Costs — General and Administrative

Six months ended June 30, 2011 as compared to six months ended June 30, 2010

Direct costs — general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer’s reserve reports and legal matters. Direct costs increased during the 2011 six months ended June 30, 2011 compared to the same period in 2010, by approximately $229,000 principally due to increased fees for professional services.

Three months ended June 30, 2011 as compared to three months ended June 30, 2010

Direct costs — general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer’s reserve reports and legal matters. Direct costs increased during the three months ended June 30, 2011 compared to the same period in 2010, by approximately $35,000 principally due to increased fees for professional services.

Year ended December 31, 2010 as compared to year ended December 31, 2009. Direct costs — general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation, independent engineer’s reserve reports and legal matters. Direct costs increased during the 2010 annual period compared to the 2009 annual period, by approximately $0.4 million principally due to increased fees for professional services related to the partnership’s SEC reporting compliance efforts.

Depreciation, Depletion and Amortization

Six months ended June 30, 2011 as compared to six months ended June 30, 2010

The DD&A expense rate per Mcfe decreased to $3.41 for the 2011 six month period, compared to $4.40 during the same period in 2010. The decrease of $0.99 in the per Mcfe rates for the 2011 period compared to the 2010 period is primarily due a decrease of $1.46 as a result of the 2010 impairment of the partnership’s Grand Valley Field. This decrease was partially offset by a net increase of $0.47 resulting from a downward revision of the partnership’s proved developed producing natural gas, NGLs and crude oil reserves in the Grand Valley Field partially offset by an upward revision in the partnership’s proved developed producing natural gas, NGLs and crude oil reserves particularly in the Wattenberg Field as of December 31, 2010. The decrease in production and the decreased DD&A expense rate resulted in an overall decreased DD&A expense of approximately $152,000 for the 2011 six month period compared to the same 2010 period.

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Three months ended June 30, 2011 as compared to three months ended June 30, 2010

The DD&A expense rate per Mcfe decreased to $3.38 for the 2011 three month period, compared to $4.38 during the same period in 2010. The decrease of $1.00 in the per Mcfe rates for the 2011 period compared to the 2010 period is primarily due to a decrease of $1.48 as a result of the 2010 impairment of the partnership’s Grand Valley Field. This decrease was partially offset by a net increase of $0.48 resulting from a downward revision of the partnership’s proved developed producing natural gas, NGLs and crude oil reserves in the Grand Valley Field partially offset by an upward revision in the partnership’s proved developed producing natural gas, NGLs and crude oil reserves in the Wattenberg Field as of December 31, 2010. The decrease in production and the decreased DD&A expense rate resulted in an overall decreased DD&A expense of approximately $79,000 for the 2011 three month period compared to the same 2010 period.

Year ended December 31, 2010 as compared to year ended December 31, 2009.

Natural gas and crude oil properties. DD&A expense related to natural gas and crude oil properties is directly related to proved reserves and production volumes. DD&A expense is primarily based upon year-end proved developed producing reserves. The pricing measurement for reserve estimations is a 12-month average of the first day of the month price for each month in the period. If prices increase, the estimated volumes of proved reserves will increase, resulting in decreases in the rate of DD&A per unit of production. If prices decrease, the estimated volumes of proved reserves will decrease, resulting in increases in the rate of DD&A per unit of production.

Changes in DD&A expense. The DD&A expense rate per Mcfe increased to $4.55 for 2010 compared to $3.87 during 2009. The increase in the per Mcfe rates for 2010 compared to 2009 is due to the changing production mix between the partnership’s Wattenberg and Grand Valley Fields, which have significantly different DD&A rates, in addition to the effect of the downward revision in the partnership’s proved developed producing natural gas, NGLs and crude oil reserves at December 31, 2009 The increased DD&A expense rate, offset by the effect of the production declines noted in previous sections, resulted in the DD&A expense remaining substantially unchanged for 2010 compared to 2009.

Loss on Impairment of Natural Gas and Crude Oil Properties

The partnership assesses its proved natural gas and crude oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which PDC, as managing general partner of the partnership. reasonably estimates the commodities to be sold. The partnership considers the receipt of the annual reserve report from independent engineers to be a triggering event. Therefore, impairment tests are completed as of December 31 each year. The estimates of future prices may differ from current market prices of natural gas and crude oil. Certain events, including but not limited to, downward revisions in estimates to the partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs, could also result in a triggering event and, therefore, a possible impairment of the partnership’s proved natural gas and crude oil properties. If during the completion of the impairment test, net capitalized costs exceed undiscounted future net cash flows, as occurred for the year ended December 31, 2010, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis, which is predominantly unobservable data or inputs (Level 3), and is measured by the amount by which the net capitalized costs exceed their fair value. The partnership’s estimated production used in the impairment testing is taken from the annual reserve report. Estimated undiscounted future net cash flows are determined using prices from the forward price curve at the measurement date. Estimated discounted future net cash flows were determined utilizing a risk adjusted discount rate that is based on rates utilized by market participants that are commensurate with the risks inherent in the development of the underlying natural gas and crude oil reserves. A decline in the forward price curves used to estimate future cash flows at December 31, 2010 accompanied by lower reserves reflected in the partnership’s annual reserve report resulted in an impairment in the fourth quarter of 2010. This downward revision to the future net cash flows resulted primarily from a 917 or 66.8% decrease in future estimated MMcfs of natural gas production due to well economics and a reduction in prices from 2009. The partnership recorded an impairment loss of $0.6 for the year ended December 31, 2010. The impairment loss resulted from the downward revision to the fair value of discounted future

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net cash flows of production activities in the Grand Valley Field in Colorado. The partnership recognized no impairment of its natural gas and crude oil properties for the year ended December 31, 2009. The partnership has recognized impairment losses from inception to December 31, 2010 of $13.0 million on its natural gas and crude oil properties since the partnership began operating in 2002.

Financial Condition Liquidity and Capital Resources

The partnership’s primary sources of cash for each of the three and six month period ended June 30, 2011, the year ended December 31, 2010 and the year ended December 31, 2009, were from funds provided by operating activities which include the sale of natural gas, NGLs and crude oil production and the realized gains from the partnership’s derivative positions. These sources of cash were primarily used to fund the partnership’s operating cost, general and administrative activities and provided monthly distributions to the investors and PDC, the managing general partner of the partnership. Additionally, the partnership’s operating cash flows were reduced by approximately $275,000 due to payments by the partnership to reduce the balance of “Due to the Managing General Partner-other, net” (See Working Capital below). The future repayment of the entire balance of “Due to the Managing General Partner-other, net” prior to withholding any distributions to fund the Additional Codell Formation Development Plan was taken into consideration when assessing the partnership’s ability to complete this plan. When this balance is repaid, any future withholdings will provide the funding for planned Wattenberg Field well refracturing or recompletion costs to be incurred beginning in 2012.

Fluctuations in the partnership’s operating cash flows are substantially driven by changes in commodity prices, in production volumes and in realized gains and losses from commodity positions. Commodity prices have historically been volatile and PDC, as managing general partner of the partnership, attempts to manage this volatility through derivatives. Therefore, the primary source of the partnership’s cash flow from operations becomes the net activity between the partnership’s natural gas, NGLs and crude oil sales and realized natural gas and crude oil derivative gains and losses. However, the partnership does not engage in speculative positions, nor does the partnership hold derivative instruments for 100% of the partnership’s expected future production from producing wells and therefore may still experience significant fluctuations in cash flows from operations. As of June 30, 2011, the partnership had natural gas and crude oil derivative positions in place covering all of the expected natural gas production and 53% of expected crude oil production for the remainder of 2011, at an average price of $4.87 per Mcf and $70.75 per Bbl, respectively. The partnership’s current derivative position average prices have declined from the significantly higher average commodity contract strike price levels in effect during the 2010 comparative period which were the result of contracts entered into during the high 2008 commodity price market; accordingly, the partnership anticipates realized gains for the next 12 months to remain substantially below gains realized in 2009 and the first quarter of 2010.

The partnership’s future operations are expected to be conducted with available funds and revenues generated from natural gas, NGLs and crude oil production activities and commodity gains. Natural gas, NGLs and crude oil production from the partnership’s existing properties are generally expected to continue a gradual decline in the rate of production over the remaining life of the wells. Therefore, the partnership anticipates a lower annual level of natural gas, NGLs and crude oil production and, in the absence of significant price increases or additional reserve development, lower revenues. The partnership also expects cash flows from operations to decline if commodity prices remain at current levels or decrease in the future. Under these circumstances decreased production would have a material negative impact on the partnership’s operations and may result in reduced cash distributions to PDC and investors through the remainder of 2011 and beyond, and may substantially reduce or restrict the partnership’s ability to participate in the additional Codell formation development activities which are more fully described in the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments-Additional Codell Formation Development Plan.”

Working Capital

The partnership had a working capital deficit at June 30, 2011 of approximately $113,000 compared to a working capital deficit of approximately $273,000 at December 31, 2010. The partnership’s working capital deficit decreased by approximately $160,000 during the six months ended June 30, 2011. This deficit arose in the second half of 2010 due primarily to the increase in Direct costs — general and administrative resulting from the

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partnership’s SEC compliance effort. These costs were in excess of cash provided by operating activities during that period and were paid by PDC and are being repaid by the partnership. The decrease in the working capital deficit was primarily due to the following changes:


	•	“Due to the Managing General Partner” decreased by approximately $275,000 between June 30, 2011 and December 31, 2010,


	•	Accounts payable and accrued expenses decreased by $28,000 between June 30, 2011 and December 31, 2010,


	•	Accounts receivable decreased by $3,000 between June 30, 2011 and December 31, 2010,


	•	Realized and unrealized derivative gains receivable decreased by $15,000 between June, 2011 and December 31, 2010, and


	•	Cash decreased by approximately $125,000 between June 30, 2011 and December 31, 2010.

The partnership had negative working capital of $0.3 million at December 31, 2010 compared to working capital of $0.4 million at December 31, 2009, a decrease of approximately $0.7 million. This decrease was primarily due to the following changes:


	•	Accounts receivable decreased by $0.1 million between December 31, 2010 and December 31, 2009.

	•	Realized derivative gains receivables decreased by $0.2 million between December 31, 2010 and December 31, 2009.

	•	“Due to the Managing General Partner-other payable,” excluding natural gas, NGLs and crude oil sales received from third parties and realized derivative gains, increased by approximately $0.4 million as of December 31, 2010 compared to December 31, 2009.

Working capital is expected to fluctuate by increasing during periods of Additional Codell Formation Development Plan funding and by decreasing during periods when payments are made for refracturing or recompletions.

Cash Flows

Cash Flows From Operating Activities

The partnership’s cash flows provided by operating activities is primarily impacted by commodity prices, production volumes, realized gains and losses from its derivative positions, operating costs and general and administrative expenses. See “— Results of Operations” above for an additional discussion of the key drivers of cash flows provided by operating activities.

Natural gas, NGLs and crude oil prices exhibit a high degree of volatility. These price variations have a material impact on the partnership’s financial results. Natural gas and NGLs prices vary by region and locality, depending upon the distance to markets, the availability of pipeline capacity and the supply and demand relationships in that region or locality. This can be especially true in the Rocky Mountain Region. The combination of increased drilling activity and the lack of local markets have resulted in local market oversupply situations from time to time. Like most producers in the region, the partnership relies on major interstate pipeline companies to construct these pipelines to increase capacity, rendering the timing and availability of these facilities beyond the partnership’s control. Crude oil pricing is predominantly driven by the physical market, supply and demand, the financial markets and global unrest.

The price at which PDC markets the natural gas produced in the Rocky Mountain Region by the partnership is based on a market basket of prices, which primarily includes natural gas sold at CIG prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby region prices. The CIG Index and other indices for production delivered to other Rocky Mountain pipelines have historically been less than the price received for natural gas produced in the eastern regions, which is primarily New York Mercantile Exchange, or NYMEX, based. This negative differential has narrowed over the last few years and is lower than historical variances. The negative

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differential of CIG relative to NYMEX averaged $0.31 and $0.32 for the three months ended June 30, 2011 and 2010, respectively.

The price the partnership receives on its natural gas sales is impacted by the PDC’s transportation, gathering and processing agreements. The partnership currently uses the “net-back” method of accounting for these arrangements related to the partnership’s natural gas sales. The partnership sells natural gas at the wellhead and collects a price and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based.

Net cash consumed by operating activities was approximately $60,000 for the six months ended June 30, 2011, compared to net cash provided by operating activities of approximately $665,000 for the comparable period in 2010. The decrease of approximately $725,000 in net cash provided by operating activities was due primarily to the following:


	•	A decrease in natural gas, NGLs and crude oil sales receipts of approximately $126,000, or 15%,


	•	A decrease in commodity price risk management realized gains receipts of approximately $276,000, or 80%, and


	•	An increase in production costs and direct costs — general and administrative payments of approximately $323,000.

Net cash provided by operating activities was $0.7 million for 2010 compared to $2.4 million for 2009, a decrease of approximately $1.7 million. The decrease in cash provided by operating activities was due primarily to the following:


	•	An increase in natural gas, NGLs and crude oil sales receipts of $0.1 million, or 9%;

	•	A decrease in commodity price risk management realized gains receipts of $0.7 million, or 63%, accompanied by increases in natural gas, NGLs and crude oil production costs of $0.5 million, or 70% and direct costs-general and administrative of $0.4 million;

	•	A decrease in “Due to Managing General Partner-other, net,” receipts of approximately $0.2 million, excluding natural gas, NGLs and crude oil sales received from third parties and realized derivative gains.

Cash Flows From Investing Activities

The partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas and crude oil or environmental protection. These amounts totaled approximately $25,000 for each of the six months ended June 30, 2011 and 2010, respectively, and approximately $53,000 and $44,000 for the years ended 2010 and 2009, respectively.

Cash Flows From Financing Activities

The partnership initiated monthly cash distributions to investors in July 2003 and has distributed $20.7 million through June 30, 2011. The tables below present cash distributions, as modified by the Preferred Cash Distributions more fully explained below, to the partnership’s investors. “Managing General Partner distributions” include amounts distributed to PDC for its managing general partner’s 20% ownership share in the partnership. “Investor Partner distributions” include amounts distributed to investors for their 80% ownership share in the partnership and include amounts distributed to PDC for limited partnership units repurchased.


	Managing		Investor
	General Partner		Partners		Total
Three Months Ended June 30,	Distributions		Distributions		Distributions

2011	$	2,032	$	17,736	$	19,768
2010	$	11,838	$	161,363	$	173,201

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	Managing		Investor
	General Partner		Partners		Total
Six Months Ended June 30,	Distributions		Distributions		Distributions

2011	$	4,105	$	36,217	$	40,322
2010	$	62,597	$	576,865	$	639,462

The decrease in total distributions for 2011 as compared to 2010 is primarily due to the significant decrease in cash flows from operating activities during 2011.


	Managing		Investor
	General Partner		Partners		Total
Year Ended	Distributions		Distributions		Distributions

2010	$	57,697	$	614,215	$	671,912
2009	$	351,057	$	1,979,524	$	2,330,581

The decrease in total distributions for 2010 as compared to 2009 is primarily due to the significant decrease in cash flows from operating activities during these respective years.

Beginning in April 2009, when the average investor’s annual rate of return fell below 12.8%, the partnership modified the standard ownership-based pro-rata allocation of partnership cash available for distribution, pursuant to the Performance Standard Obligation outlined in Section 4.02 of the partnership agreement. Distributions paid to PDC were reduced and distributions to the investors were increased, by $3,959 and $65,296 for the six month periods ended June 30, 2011 and 2010, respectively, and $76,686 and $115,058 for the years ended December 31, 2010 and 2009, respectively, as a result of the Preferred Cash Distribution made under the terms of Section 4.02. Because of the expected production declines related to the partnership’s mature natural gas and oil operations, PDC believes performance obligation allocation rate modifications are likely to continue until June 2013, when the provision expires under the terms of the partnership agreement.

Additionally, due to the Additional Codell Formation Development Plan, PDC’s and investors’ distributions are expected to decrease in 2011. For additional information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments- Additional Codell Formation Development Plan.”

Critical Accounting Policies and Estimates

PDC has identified the following policies as critical to business operations and the understanding of the results of the operations of the partnership. The following is not a comprehensive list of all of the partnership’s accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by accounting principles generally accepted in the United States, with no need for management’s judgment in their application. There are also areas in which management’s judgment in selecting any available alternative would not produce a materially different result. However, certain of the partnership’s accounting policies are particularly important to the portrayal of the partnership’s financial position and results of operations and PDC may use significant judgment in their application; as a result these policies are subject to inherent degree of uncertainty. In applying these policies, PDC uses its judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry and information available from other outside sources, as appropriate. The partnership’s critical accounting policies and estimates are as follows:

Natural Gas and Crude Oil Properties

The partnership accounts for its natural gas and crude oil properties under the successful efforts method of accounting. Costs of proved developed producing properties and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves.

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Annually, PDC engages an independent petroleum engineer to prepare a reserve and economic evaluation of the partnership’s properties on a well-by-well basis as of December 31. The process of estimating and evaluating natural gas, NGLs and crude oil reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent PDC’s most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect the partnership’s DD&A expense, a change in the partnership’s estimated reserves could have an effect on its net income.

Proved developed reserves are those natural gas, NGLs and crude oil quantities expected to be recovered from currently producing zones under the continuation of present operating methods. Proved undeveloped reserves, or PUDs, are those reserves expected to be recovered from existing wells where a relatively major expenditure is required for additional reserve development.

The partnership assesses its natural gas and crude oil properties for possible impairment by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which management reasonably estimates commodities to be sold. The estimates of future prices may differ from current market prices of natural gas, NGLs and crude oil. Any downward revisions in estimates to the partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future net cash flows and an impairment of the partnership’s natural gas and crude oil properties. Although the partnership’s cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results.

Natural Gas, NGLs and Crude Oil Sales Revenue Recognition

Natural gas, NGLs and crude oil sales are recognized when production is sold to a purchaser at a determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. The partnership records sales revenue based on an estimate of the volumes delivered at prices tied to market indexes, adjusted based on agreed upon contract terms. PDC estimates the partnership’s sales volumes based on PDC’s measured volume readings. PDC then adjusts the partnership’s natural gas, NGL and crude oil sales in subsequent periods based on the data received from the partnership’s purchasers that reflects actual volumes received. The partnership receives payment for sales from one to three months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded up to two months later. Historically, differences have been immaterial.

Fair Value of Financial Instruments

Determination of Fair Value. Fair value accounting standards have established a fair value hierarchy that prioritizes the inputs used in applying a valuation methodology. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:


	•	Level 1 — Quoted prices (unadjusted) in active markets for identical assets or liabilities.


	•	Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other

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		than quoted prices that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means.


	•	Level 3 — Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.

Derivative Financial Instruments. The Partnership measures the fair value of its derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner’s credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner’s counterparties’ credit standings on the fair value of derivative assets, both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. The counterparties to the Partnership’s derivative instruments are primarily financial institutions. The Managing General Partner validates the fair value measurement through (1) the review of counterparty statements and other supporting documentation, (2) the determination that the source of the inputs are valid, (3) the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. While the Managing General Partner uses common industry practices to develop its valuation techniques, changes in the pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes its valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

Off-Balance Sheet Arrangements

As of June 30, 2011, the partnership had no existing off-balance sheet arrangements, as defined under SEC rules, which have or are reasonably likely to have a material current or future effect on the partnership’s financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

DELIVERY OF DOCUMENTS TO INVESTORS SHARING AN ADDRESS

Only one copy of this proxy statement is being delivered to multiple investors sharing an address unless PDC has received contrary instructions from one of more of such investors. This practice, known as “householding,” is designed to reduce duplicative mailings and save significant printing and postage costs. PDC will deliver promptly, upon a written or oral request, a separate copy of this proxy statement to an investor at a shared address to which only one copy of this proxy statement was delivered. An investor wishing to make such a request may contact PDC by mail at 1775 Sherman Street, Suite 3000, Denver, Colorado 80203, or by phone at 303-860-5800. At any time, an investor who no longer wishes to participate in householding and would prefer to receive a separate proxy statement in the future, or an investor who is receiving multiple copies of the proxy statement and wishes to receive a single copy in the future, may contact PDC by mail or by phone at the address and phone number set forth above.

WHERE YOU CAN FIND MORE INFORMATION

Each of PDC and the partnership is subject to the informational and reporting requirements of the Securities Exchange Act of 1934. Each of PDC and the partnership is required to file annual, quarterly and current reports and other information with the SEC. SEC filings that have been made by PDC or the partnership are available to the public over the internet at the SEC’s web site at http://www.sec.gov. You may also read and copy any document that PDC or the partnership files with the SEC at its public reference room at 100 F Street, N.E., Room 1850, Washington, D.C. 20549 Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.

The investors will be entitled to access PDC’s, the merger sub’s and the partnership’s corporate records in the manner permitted by applicable federal and Nevada and West Virginia state laws. None of PDC, the merger sub, the partnership or Messrs. Shellum, Brookman or Amidon has made any other provision to grant the investors access to

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the corporate records of PDC, the merger sub or the partnership, or for the investors to obtain counsel or appraisal services at PDC’s, the merger sub’s or the partnership’s expense.

The opinion of the special committee’s fairness advisor, dated June 11, 2011, will be made available for inspection and copying at the principal executive offices of PDC during its regular business hours by any interested investor or by a representative of an investor who has been so designated in writing. A copy of the opinion will be transmitted by PDC to any interested investor or to a representative of an investor who has been so designated in writing upon written request and at the expense of the requesting investor.

COMMONLY USED OIL AND GAS TERMS

The definitions set forth below shall apply to the indicated terms as used in this document. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

“Bbl” means a one barrel, or 42 U.S. gallons of liquid volume.

“Bcf” means one billion cubic feet under prescribed conditions of pressure and temperature and represents the basic unit for measuring the production of natural gas.

“BTU” means British Thermal Unit. One British Thermal Unit is the amount of heat required to raised the temperature of one pound of water by one degree Fahrenheit.

“completion” means the installation of permanent equipment for the production of oil or gas.

“development well” means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

“dry hole” means a well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well.

“MBbl” means one thousand Bbls.

“Mcf” means one thousand cubic feet.

“Mcfe” means one thousand cubic feet of natural gas equivalent.

“MMbtu” means One Million BTUs.

“MMcf” means one million cubic feet.

“MMcfe” means one million cubic feet of natural gas equivalent.

“natural gas liquids” or “NGLs” means hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs consist primarily of ethane, propane, butane, and natural gasolines.

“NYMEX” means the New York Mercantile Exchange.

“proved developed producing reserves” means proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods.

“proved developed reserves” means the combination of proved developed producing and proved developed non-producing reserves.

“proved reserves” means those estimated quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonable certain, regardless of whether deterministic or probabilistic methods are used for the estimation.

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“proved undeveloped reserves” or “PUDs” means proved 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.

“reasonable certainty” means a high degree of confidence.

“reserves” means estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substance to market, and all permits and financing required to implement the project.

“reservoir” means a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“royalty” means an interest in an natural gas and oil lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

“working interest” means an interest in an natural gas and oil lease that gives the owner of the interest the right to drill for and produce natural gas and oil on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden.

“workover” means operations on a producing well to restore or increase production.

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AGREEMENT AND PLAN OF MERGER

THIS AGREEMENT AND PLAN OF MERGER, (this “Agreement”) is made on June 20, 2011, by and among PDC 2002-D LIMITED PARTNERSHIP, a West Virginia limited partnership (the ‘‘Partnership”), PETROLEUM DEVELOPMENT CORPORATION, a Nevada corporation (“PDC”), and DP 2004 MERGER SUB, LLC, a Delaware limited liability company (“LLC”).

RECITALS

A. The Partnership is engaged in the business of oil and gas development and production. The Partnership is comprised of PDC as the general partner (sometimes referred to herein as the ‘‘Managing General Partner”) and a limited partner, and various investors in the Partnership, other than PDC and any of its affiliates, as limited partners (the ‘‘Investors”).

B. LLC is a wholly owned subsidiary of PDC.

C. PDC, as the Managing General Partner of the Partnership, for itself, and as the sole member of LLC, has approved this Agreement, has deemed this Agreement to be advisable and has approved the merger of the Partnership with and into LLC (the “Merger”) in accordance with the terms of this Agreement, the Delaware Limited Liability Act (the “LLC Act”) and the West Virginia Limited Partnership Act, W. Va. Code § 47-9-1 et seq. (the “LP Act”), as contemplated hereby.

D. PDC, as Managing General Partner, intends to solicit the vote of the holders of a majority of outstanding partnership interests of the Partnership held by Investors. Subject to certain limitations, upon consummation of the merger, the Investors will have the right to receive an amount in cash subject to the terms and conditions described herein.

NOW, THEREFORE, in consideration of the foregoing and the respective representations, warranties, covenants and agreements set forth herein, the parties hereto agree as follows:

ARTICLE I

THE MERGER

Section 1.1 The Merger. Upon the terms and subject to the conditions of this Agreement and in accordance with the LLC Act and the LP Act, at the Effective Date (as defined in Section 1.3 hereof) (i) the Partnership shall be merged with and into LLC, (ii) the separate existence of the Partnership shall cease and LLC shall continue as the surviving entity (sometimes hereinafter referred to as the “Surviving Entity”), (iii) all the rights, privileges, immunities, powers and franchises of the Partnership shall vest in the Surviving Entity, and (iv) the liabilities of the Partnership shall be the obligations, duties, debts and liabilities of the Surviving Entity.

Section 1.2 Closing. Unless this Agreement shall have been terminated and the transactions contemplated herein abandoned, and subject to the satisfaction or waiver of the conditions set forth in Article VII, the closing of the Merger (the “Closing”) will take place at the offices of PDC, or such other place as PDC determines, on a date to be specified by the parties, which date shall be the date on which the Certificate of Merger described in Section 1.3 is to be filed with the West Virginia Secretary of State and the Delaware Secretary of State (the “Closing Date”).

Section 1.3 Effective Date. Subject to the provisions of this Agreement, on the Closing Date, LLC and the Partnership shall cause an appropriate Certificate of Merger (the ‘‘Certificate of Merger”) to be executed and filed with the Secretary of State of the State of West Virginia (the “West Virginia Secretary of State”) and the Secretary of State of the State of Delaware (the “Delaware Secretary of State”) in such form as required by the LLC Act and the LP Act. The Merger shall become effective as of the Closing Date, and such time is hereinafter referred to as the “Effective Date.”

Section 1.4 Certificate of Limited Partnership; Limited Partnership Agreement; LLC Agreement. Upon the Effective Date, the Certificate of Limited Partnership, as amended (the ‘‘Certificate of Limited Partnership”) and the Limited Partnership Agreement of the Partnership (the “Limited Partnership Agreement”), as in effect

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immediately prior to the Merger, shall be deemed cancelled and of no further force and effect. The Surviving Entity shall be governed according to and consistent with the LLC Act, the Limited Liability Company Agreement of LLC in effect as of the Closing Date, as that agreement may be amended from time to time (the “LLC Agreement”) and the Certificate of Formation for LLC filed with the Delaware Secretary of State on May 7, 2010 (the “Certificate of Formation”).

Section 1.5 Sole Member and Principal Office of the Surviving Entity. PDC shall be the sole member of the Surviving Entity with all powers granted to PDC under the LLC Agreement and the LLC Act. The Principal Office of the surviving entity shall be 1775 Sherman Street, Suite 3000, Denver, Colorado 80203.

ARTICLE II

EFFECT OF MERGER AND LIQUIDATION OF INVESTOR UNITS

Section 2.1 Termination of Partnership. On the Effective Date, by virtue of the Merger and without any action on the part of the Partnership, PDC or LLC, the Partnership shall cease to exist as a separate legal entity.

Section 2.2 Liquidation of Investor Partnership Units. On the Effective Date, the Partnership shall liquidate all of the units of interest in the Partnership (each a “Unit” and collectively the “Units”) held by the Investors as of the Effective Date and each Unit held by an Investor shall automatically be converted into the right to receive $4,024 per Unit, plus the sum of amounts withheld from per Unit cash distributions by the Partnership from October 1, 2010 through August 31, 2011 for the Partnership’s additional development plan in the Codell formation, less the sum of the per Unit cash distributions made after August 31, 2011 and before the Closing Date, and subject to any adjustments made pursuant to Section 2.3 herein (the ‘‘Per Unit Price,” which shall be proportionally adjusted for partial Units). PDC shall deliver to each Investor the cash payment for such Investor’s liquidated Units within 30 days after completion of the Merger.

Section 2.3 Adjustments.

(a) On the Adjustment Date, the Per Unit Price will be increased by the sum of the Oil Price Adjustment (as defined below), if any, and the Gas Price Adjustment (as defined below), if any. For purposes hereof, the “Adjustment Date” means at 5:00 p.m. (New York City time) on the date one day before the date the Proxy Statement relating to the Special Meeting is filed with the Securities and Exchange Commission.

(b) For each increment of $5.00 per Bbl by which (x) the arithmetic average of the five-year NYMEX futures price per Bbl for oil as of the Adjustment Date exceeds (y) the arithmetic average of the five-year NYMEX futures price per Bbl for oil as of March 31, 2011, there will be a preliminary increase of $275 per Unit (the sum of all such incremental increases, the ‘‘Positive Oil Price Adjustment”). For avoidance of doubt, if (x) the arithmetic average of the five-year NYMEX futures price per Bbl for oil as of the Adjustment Date does not exceed (y) the arithmetic average of the five-year NYMEX futures price per Bbl for oil as of March 31, 2011 by at least $5.00 per Bbl, there will be no preliminary increase of $275 per Unit and the Positive Oil Price Adjustment and the Oil Price Adjustment (as defined below) will be equal to $0.

(c) For each increment of $0.50 per Mcf by which (x) the arithmetic average of the five-year NYMEX futures price per Mcf for gas as of March 31, 2011 exceeds (y) the arithmetic average of the five-year NYMEX futures price for gas as of the Adjustment Date, there will be a preliminary decrease of $200 per Unit (the sum of all such incremental decreases, the ‘‘Negative Gas Price Adjustment”). For avoidance of doubt, if (x) the arithmetic average of the five-year NYMEX futures price per Mcf for gas as of March 31, 2011 does not exceed (y) the arithmetic average of the five-year NYMEX futures price for gas as of the Adjustment Date by at least $0.50 per Mcf, there will be no preliminary decrease of $200 per Unit and the Negative Gas Price Adjustment will be equal to $0.

(d) The “Oil Price Adjustment” will be equal to the cash amount in dollars that the Positive Oil Price Adjustment exceeds the absolute value of the Negative Gas Price Adjustment. For avoidance of doubt, if the absolute value of the Negative Gas Price Adjustment exceeds the Positive Oil Price Adjustment on the Adjustment Date, the Oil Price Adjustment will be an amount equal to $0.

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(e) For each increment of $0.50 per Mcf by which (x) the arithmetic average of the five-year NYMEX futures price per Mcf for gas as of the Adjustment Date exceeds (y) the arithmetic average of the five-year NYMEX futures price per Mcf for gas as of March 31, 2011, there will be a preliminary increase of $200 per Unit (the sum of all such incremental increases, the ‘‘Positive Gas Price Adjustment”). For avoidance of doubt, if the arithmetic average of the five-year NYMEX futures price per Mcf for gas as of the Adjustment Date does not exceed the arithmetic average of the five-year NYMEX futures price per Mcf for gas as of March 31, 2011 by at least $0.50 per Mcf, there will be no preliminary increase of $200 per Unit and the Positive Gas Price Adjustment and the Gas Price Adjustment (as defined below) will be equal to $0.

(f) For each increment of $5.00 per Bbl by which (x) the arithmetic average of the five-year NYMEX futures price per Bbl for oil as of March 31, 2011 exceeds (y) the arithmetic average of the five-year NYMEX futures price per Bbl for oil as of the Adjustment Date, there will be a preliminary decrease of $275 per Unit (the sum of all such incremental decreases, the “Negative Oil Price Adjustment”). For avoidance of doubt, if (x) the arithmetic average of the five-year NYMEX futures price per Bbl for oil as of March 31, 2011 does not exceed (y) the arithmetic average of the five-year NYMEX futures price per Bbl for oil as of the Adjustment Date by at least $5.00 per Bbl, there will be no preliminary decrease of $275 per Unit and the Negative Oil Price Adjustment will be equal to $0.

(g) The “Gas Price Adjustment” will be equal to the cash amount in dollars that the Positive Gas Price Adjustment exceeds the absolute value of the Negative Oil Price Adjustment. For avoidance of doubt, if the absolute value of the Negative Oil Price Adjustment exceeds the Positive Gas Price Adjustment on the Adjustment Date, the Gas Price Adjustment will be an amount equal to $0.

(h) As used in this Section 2.3, the following terms have the respective meanings set forth below:

‘‘Bbl” means one barrel, or 42 U.S. gallons, of liquid volume.

‘‘Mcf” means one thousand cubic feet.

‘‘NYMEX” means the New York Mercantile Exchange.

Section 2.4 Appraisal. Notwithstanding anything in this Agreement to the contrary, Units that are outstanding immediately prior to the Closing Date and that are held by any Investor who is entitled to demand, and properly demands, appraisal of such Units (“Appraisal Units”) pursuant to, and who complies in all respects with, the West Virginia Business Corporations Act (the “WVBCA”) shall not be converted into the right to receive the Per Unit Price as provided in Section 2.2, but rather the holders of such Appraisal Units shall be entitled to payment of the “fair value” (as defined in the WVBCA) of such Appraisal Units in accordance with the Act (and at the Closing Date, such Appraisal Units shall no longer be outstanding and shall automatically be cancelled and shall cease to exist, and the holders thereof shall cease to have any right with respect thereto, except the right to receive the fair value of such Appraisal Unit in accordance with the WVBCA); provided, however, that if any such holder shall fail to perfect or otherwise shall waive, withdraw or lose the right to appraisal under the WVBCA, then the right of such holder to be paid the fair value of such holder’s Appraisal Units shall cease and such Appraisal Units shall be deemed to have been converted as of the Closing Date into the right to receive the Per Unit Price as provided in Section 2.2. The Partnership shall give PDC (i) prompt notice of any demands for appraisal received by the Partnership, withdrawals of such demands, and any other instruments served pursuant to the WVBCA and received by the Partnership and (ii) the opportunity to direct all negotiations and proceedings with respect to demands for appraisal under the WVBCA.

Section 2.5 Extinguishment of PDC’s Partnership Interests. On the Effective Date, all of PDC’s interest in the Partnership (including, without limitation, its Managing General Partner Interest and all Units owned by PDC or any of its affiliates) shall be extinguished.

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ARTICLE III

REPRESENTATIONS AND WARRANTIES OF THE PARTNERSHIP

The Partnership represents and warrants to PDC and LLC that:

Section 3.1 Organization. The Partnership is a limited partnership, duly formed and validly existing under the laws of the State of West Virginia, and has all requisite power and authority and all necessary governmental approvals to own, lease and operate its properties and to carry on its business as it is now being conducted.

Section 3.2 Authorization; Validity of Agreement.

(a) The Partnership has the requisite power and authority to execute and deliver this Agreement and to consummate the transactions contemplated hereby.

(b) The execution and delivery by the Partnership of this Agreement and the consummation of the transactions contemplated hereby have been duly authorized in accordance with the Certificate of Limited Partnership and the Limited Partnership Agreement, and no other proceedings on the part of the Partnership are necessary to authorize the execution and delivery of this Agreement by the Partnership and the consummation of the transactions contemplated hereby.

(c) This Agreement has been duly executed and delivered by the Partnership and, assuming due authorization, execution and delivery of this Agreement by PDC and LLC, is a legal, valid and binding obligation of the Partnership, enforceable against the Partnership in accordance with its terms, except that such enforcement may be subject to or limited by (i) bankruptcy, insolvency or other similar laws, now or hereafter in effect, affecting creditors’ rights generally, and (ii) the effect of general principles of equity (regardless of whether enforceability is considered in a proceeding at law or in equity).

Section 3.3 Opinion of the Committee’s Financial Advisor. The Committee has received a written opinion from Houlihan Lokey Howard & Zukin Financial Advisors, Inc. to the effect that, subject to certain assumptions, qualifications, limitations and other matters, as of the date of such opinion, the consideration to be received by the Investors in the Merger pursuant to this Agreement is fair to such Investors from a financial point of view.

Section 3.4 Required Consent. On June 11, 2011, a special committee (the ‘‘Committee”) of the Board of Directors of PDC, the Managing General Partner of the Partnership, at a meeting duly called and held, by the vote of the Committee members present at such meeting, a quorum of the Committee having been satisfied in accordance with the bylaws of PDC, (i) determined that this Agreement and the Merger are advisable and in the best interests of the Partnership, (ii) approved this Agreement, the Merger and the other transactions contemplated hereby, and (iii) resolved to recommend that the Investors of the Partnership vote to approve this Agreement.

Section 3.5 No Violations or Consents.

(a) Neither the execution and delivery of this Agreement by the Partnership nor the consummation by the Partnership of the transactions contemplated hereby will (i) violate any provision of the Certificate of Limited Partnership or the Limited Partnership Agreement, (ii) result in a violation or breach of, or constitute (with or without due notice or lapse of time or both) a default or give rise to any right of termination, cancellation or acceleration under, any of the terms, conditions or provisions of any material note, bond, mortgage, indenture, guarantee, other evidence of indebtedness, license, lease, contract, agreement or other instrument or obligation to which the Partnership is a party or by which any of its assets may be bound or (iii) violate any order, writ, injunction, decree, statute, rule or regulation applicable to the Partnership.

(b) No filing or registration with, notification to, or authorization, consent or approval of, any governmental entity is required in connection with the execution and delivery of this Agreement by the Partnership or the consummation by the Partnership of the transactions contemplated hereby, except (i) the filing of the Certificate of Merger with the West Virginia Secretary of State and the Delaware Secretary of State and (ii) any

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filing required to be made with the Securities and Exchange Commission related to the proxy materials provided in connection with this Agreement or the transactions contemplated thereby.

Section 3.6 No Other Representations or Warranties. Except for the representations and warranties contained in this Article III, neither the Partnership nor any other person makes any other express or implied representation or warranty on behalf of the Partnership.

ARTICLE IV

REPRESENTATIONS AND WARRANTIES OF PDC AND LLC

Each of PDC and LLC represents and warrants to the Partnership as follows:

Section 4.1 Organization. PDC and LLC are each entities, duly formed, validly existing, and in good standing under the laws of the State of Nevada and the State of Delaware, respectively, and each has all requisite corporate or limited liability company (as appropriate) power and authority and all necessary governmental approvals to own, lease and operate its properties and to carry on its respective business as it is now being conducted.

Section 4.2 Authorization; Validity of Agreement.

(a) Each of PDC and LLC has the requisite corporate and limited liability company (as appropriate) power and authority to execute and deliver this Agreement and to consummate the transactions contemplated hereby.

(b) The execution and delivery by each of PDC and LLC of this Agreement and the consummation of the transactions contemplated hereby have been duly authorized by the Board of Directors of PDC and the Board of Managers of LLC and no other proceedings on the part of PDC or LLC are necessary to authorize the execution and delivery of this Agreement by PDC or LLC and the consummation of the transactions contemplated hereby.

(c) This Agreement has been duly executed and delivered by each of PDC and LLC and, assuming due authorization, execution and delivery of this Agreement by the Partnership, is a legal, valid and binding obligation of PDC and LLC, enforceable against PDC and LLC in accordance with its terms, except that such enforcement may be subject to or limited by (i) bankruptcy, insolvency or other similar laws, now or hereafter in effect, affecting creditors’ rights generally, and (ii) the effect of general principles of equity (regardless of whether enforceability is considered in a proceeding at law or in equity).

Section 4.3 Required Consent.

(a) On April 15, 2011, the Board of Directors of PDC (without the Committee members participating), at a meeting duly called and held, by the vote of the directors present at such meeting, a quorum of the Board of Directors having been satisfied in accordance with the bylaws of PDC, approved this Agreement, the Merger and the other transactions contemplated hereby. Subsequently, PDC approved the Merger and adopted this Agreement.

(b) On June 20, 2011, the sole member of LLC, by written consent, (i) determined that this Agreement and the Merger are advisable and (ii) approved this Agreement, the Merger and the other transactions contemplated hereby. Subsequently, LLC approved the Merger and adopted this Agreement.

Section 4.4 No Violations or Consents.

(a) Neither the execution and delivery of this Agreement by PDC or LLC nor the consummation by PDC or LLC of the transactions contemplated hereby will (i) violate any provision of PDC’s Second Amended and Restated Certificate of Incorporation or Bylaws, as amended and restated, or LLC’s Certificate of Formation or LLC Agreement, (ii) result in a violation or breach of, or constitute (with or without due notice or lapse of time or both) a default or give rise to any right of termination, cancellation or acceleration under, any of the terms, conditions or provisions of any material note, bond, mortgage, indenture, guarantee, other evidence of indebtedness, license, lease, contract, agreement or other instrument or obligation to which PDC or LLC is a

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party or by which any of its assets may be bound or (iii) violate any order, writ, injunction, decree, statute, rule or regulation applicable to PDC or LLC.

(b) No filing or registration with, notification to, or authorization, consent or approval of, any governmental entity is required in connection with the execution and delivery of this Agreement by PDC or LLC or the consummation by PDC or LLC of the transactions contemplated hereby, except (i) the filing of the Certificate of Merger with the West Virginia Secretary of State and the Delaware Secretary of State and (ii) any filing required to be made with the Securities and Exchange Commission related to the proxy materials provided in connection with the Agreement or the transactions contemplated thereby.

Section 4.5 No Other Representations or Warranties. Except for the representations and warranties contained in this Article IV, neither PDC, LLC nor any other person makes any other express or implied representation or warranty on behalf of PDC or LLC.

ARTICLE V

CLOSING CONDITIONS

Section 5.1 Conditions to Each Party’s Obligation to Effect the Merger. The respective obligation of each party to effect the Merger shall be subject to the satisfaction on or prior to the Closing Date of each of the following conditions:

(a) The holders of at least a majority of the issued and outstanding Units held by Investors shall have approved, at a special meeting of the Partnership held for that purpose (the “Special Meeting”), (i) an amendment to the Limited Partnership Agreement in a form that is reasonably acceptable to the Committee that expressly permits the Investors to approve this Agreement, the Merger and the transactions contemplated thereby and (ii) this Agreement, the Merger and the transactions contemplated thereby;

(b) No provision of any applicable law, rule or regulation and no judgment, order or decree shall make the Merger illegal or prohibit the consummation of the Merger and the transactions related thereto;

(c) No suit, action or proceeding shall have been filed or otherwise be pending against PDC, LLC or any officer, director (including any member of the Committee), manager, member or affiliate of PDC or LLC challenging the legality or any aspect of this Agreement, the Merger or the transactions related thereto; and

(d) The parties to the Merger shall have made all filings and registrations with, and notifications to, all third parties, including, without limitation, lenders and all appropriate regulatory authorities, required for consummation of the transactions contemplated by this Agreement (other than the filing and recordation of appropriate merger documents required by the LLC Act or LLP Act, as applicable), and all approvals and authorizations and consents of all third parties, including, without limitation, lenders and all regulatory authorities, required for consummation of the transactions contemplated by this Agreement shall have been received and shall be in full force and effect, except for such filings, registrations, notifications, approvals, authorizations and consents, the failure of which to make or obtain would not have a material adverse effect on the business or financial condition of PDC, LLC or the Partnership or the ability of PDC, LLC or the Partnership to consummate the transactions contemplated by this Agreement.

Section 5.2 Conditions to the Obligation of the Partnership to Effect the Merger. The obligation of the Partnership to effect the Merger is further subject to the satisfaction or waiver at or prior to the Closing Date of the following conditions:

(a) The representations and warranties of PDC and LLC set forth in this Agreement shall be true and correct as of the Closing Date; and

(b) PDC and LLC shall have each performed in all material respects all of their respective obligations required to be performed by them under this Agreement at or prior to the Closing Date.

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Section 5.3 Conditions to Obligations of PDC and LLC to Effect the Merger. The obligation of PDC and LLC to effect the Merger is further subject to the satisfaction or waiver at or prior to the Closing Date of the following condition:

(a) Since the date hereof, no event, circumstance, condition, development or occurrence causing, resulting in or having, or reasonably expected to cause, result in or have, a material adverse effect on the Partnership’s business, operations, properties (in all cases taken as a whole), condition (financial or otherwise), results of operations, assets (in all cases taken as a whole), liabilities, or cash flows.

ARTICLE VI

ADDITIONAL AGREEMENTS

Section 6.1 Special Meetings; Proxies. As soon as reasonably practicable after the execution of this Agreement, PDC will take all action necessary to duly call, give notice of, convene and hold the Special Meeting to consider and vote upon approval of this Agreement and the amendment to the Limited Partnership Agreement. PDC will use its commercially reasonable efforts to solicit from the Investors proxies in favor of this Agreement and the amendment to the Limited Partnership Agreement, and to take all other action necessary or advisable to secure any vote or consent of the Investors required by the Limited Partnership Agreement, this Agreement or applicable law to effect the Merger.

Section 6.2 Proxy Statement. PDC will file with the Securities and Exchange Commission (the “SEC”) under the Securities Exchange Act of 1934, as amended, a preliminary proxy statement (the “Preliminary Proxy”) and a definitive proxy statement (the “Proxy Statement”) relating to the Special Meeting, and any amendments or supplements thereto as PDC may deem to be required or appropriate. PDC shall cause the Proxy Statement to be mailed to the Investors as soon as practicable in accordance with applicable federal and state law. PDC shall provide to the Committee, prior to filing, drafts of the Preliminary Proxy, the Proxy Statement and any amendments or supplements thereto, give the Committee and its counsel reasonable opportunity to comment on the same, and provide the Committee and its counsel with any other documents reasonably related to the Proxy Statement (including any correspondence from or to the SEC or its staff concerning the Preliminary Proxy, the Proxy Statement, or any supplement or amendment thereto).

Section 6.3 Additional Agreements. Subject to the terms and conditions herein provided, each of the parties hereto agrees to use its commercially reasonable efforts to obtain in a timely manner all waivers, consents and approvals and to effect all registrations and filings, and to use its commercially reasonable efforts to take, or cause to be taken, all other actions and to do, or cause to be done, all other things, necessary, proper or advisable under applicable laws and regulations to consummate and make effective as promptly as practicable the transactions contemplated by this Agreement.

ARTICLE VII

TERMINATION

Section 7.1 Termination. This Agreement may be terminated and the Merger contemplated hereby may be abandoned, in whole or in part, with respect to the Partnership, at any time prior to the Effective Time, whether before or after approval of the Merger by the Investors:

(a) By mutual written consent of all the parties hereto (with the Committee required to approve any matter for the Partnership);

(b) By any party hereto (with the Committee required to approve any matter for the Partnership), if:

(i) the Closing shall not have occurred by December 15, 2011;

(ii) there shall be any applicable law, rule or regulation that makes consummation of the Merger illegal or otherwise prohibited or if any judgment, injunction, order or decree enjoining any party from

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consummating the Merger is entered and such judgment, injunction, order or decree shall have become final and non-appealable; or

(iii) there shall be filed or pending any suit, action or proceeding against PDC, LLC or any officer, director, manager, member or affiliate of PDC or LLC challenging the legality or any aspect of the Merger or the transactions related thereto;

(c) By the Partnership (with the Committee required to approve any matter for the Partnership), if PDC or LLC shall have failed to perform its agreements and covenants contained herein, and such failure has a material adverse effect on PDC or LLC, or materially and adversely affects the transactions contemplated by this Agreement, and is either incapable of being cured or is not cured by PDC or LLC within 30 days following written notice thereof from the Committee;

(d) By PDC, if the Partnership shall have failed to perform its agreements and covenants contained herein, and such failure has a material adverse effect on the Partnership, or materially and adversely affects the transactions contemplated by this Agreement, and is either incapable of being cured or is not cured by the Partnership within 30 days following written notice thereof from PDC; and

(e) Prior to obtaining the required vote of the Investors, by the Committee on behalf of the Partnership, if the Partnership (A) has materially complied with its obligations under this Agreement and (B) has entered into a definitive acquisition agreement providing for a Superior Proposal (as defined below); provided that the Partnership may not enter into any such definitive acquisition agreement or terminate this Agreement pursuant to this Section 7.1(e) until at least five days have passed after the Committee informs PDC of its intention to accept a Superior Proposal (during which time PDC may respond to any Superior Proposal). “Superior Proposal” means a bona fide written offer, obtained after the date hereof and not in breach of this Agreement, made by a third party to the Committee to acquire, directly or indirectly, for consideration consisting of cash, all of the Investors’ interests in the Partnership (i) which is not subject to a financing contingency, (ii) which is otherwise on terms and conditions which the Committee determines in its good faith judgment (after consultation with outside counsel and a financial advisor of national reputation) to be more favorable to the Investors from a financial point of view than the Merger and this Agreement and the other transactions contemplated hereby, taking into account at the time of determination any changes to the terms of this Agreement that as of that time had been agreed to by PDC and LLC in writing, and (iii) which is reasonably capable of being completed, taking into account any approval requirements and all financial, legal, operational (e.g., related to drilling, gathering, production, transportation and other relevant matters), regulatory and other aspects of such proposal.

Section 7.2 Effect of Termination. In the event of termination of this Agreement by a party as provided in Section 7.1, written notice thereof shall promptly be given to the other party or parties and this Agreement shall forthwith terminate without further action by any of the parties hereto. If this Agreement is terminated as provided, however, there shall be no liabilities or obligations hereunder on the part of any party hereto except as provided in Section 8.1 and except that nothing herein shall relieve any party hereto from liability for any breach of this Agreement.

ARTICLE VIII

MISCELLANEOUS

Section 8.1 Fees and Expenses. Whether or not the Merger is consummated, all costs and expenses incurred by PDC, the Partnership and LLC in connection with this Agreement and the transactions contemplated hereby (including without limitation the solicitation of proxies in connection therewith) shall be paid by PDC.

Section 8.2 Amendment. The parties may amend or cancel this Agreement prior to the Effective Date, by action taken or authorized by their Board of Directors, managers, members or Managing General Partner (through the Committee), as appropriate. This Agreement may not be amended, supplemented or modified except by an instrument in writing signed on behalf of each of the parties hereto.

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Section 8.3 Waiver. At any time prior to the Closing Date, the parties hereto may, to the extent provided by applicable law, (a) extend the time for the performance of any of the obligations or other acts of the other parties hereto, (b) waive any inaccuracies in the representations and warranties contained herein or in any document delivered pursuant hereto, and (c) waive compliance with any of the agreements or conditions contained herein; provided, however, that the parties may not waive the condition set forth in Section 5.1(a). Any such extension or waiver shall not operate as an extension or waiver of, or estoppel with respect to, any subsequent failure of compliance or other failure. Any agreement on the part of a party hereto to any such extension or waiver shall be valid against such party if set forth in an instrument in writing signed by such party.

Section 8.4 Survival. The respective representations and warranties of the parties hereto contained herein shall not survive beyond the Effective Date. The covenants and agreements of the parties hereto shall survive the Effective Date without limitation (except for those that, by their terms, contemplate a shorter survival period).

Section 8.5 Notices. All notices and other communications hereunder shall be in writing and shall be deemed given upon (a) transmitter’s confirmation of a receipt of a facsimile transmission, (b) confirmed delivery by a standard overnight carrier or when delivered by hand or (c) the expiration of five business days after the day when mailed in the United States by certified or registered mail, postage prepaid, addressed to the principal offices of the recipient.

Section 8.6 Headings. The headings contained in this Agreement are for reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement.

Section 8.7 Counterparts. This Agreement may be executed in two or more counterparts, each of which shall be deemed an original but all of which shall be considered one and the same agreement.

Section 8.8 Entire Agreement. This Agreement constitutes the entire agreement, and supersedes all prior agreements and understandings (written and oral), among the parties with respect to the subject matter hereof.

Section 8.9 Parties in Interest. This Agreement shall be binding upon and inure solely to the benefit of each party hereto, and nothing in this Agreement, express or implied, is intended to or shall confer upon any other person any rights, benefits or remedies of any nature whatsoever under or by reason of this Agreement.

Section 8.10 Severability. If any term, provision, covenant or restriction of this Agreement is held by a court of competent jurisdiction or other authority to be invalid, void, unenforceable or against its regulatory policy, the remainder of the terms, provisions, covenants and restrictions of this Agreement shall remain in full force and effect and shall in no way be affected, impaired or invalidated.

Section 8.11 Governing Law. This Agreement shall be governed and construed in accordance with the laws of the State of Delaware without giving effect to the principles of conflicts of law thereof.

Section 8.12 Assignment. Neither this Agreement nor any of the rights, interests or obligations hereunder shall be assigned by either of the parties hereto without the prior written consent of the other party.

Section 8.13 Further Assurances. Each party hereto covenants and agrees to promptly execute and deliver to the requesting party such other documents, instruments of transfer, etc. as may be requested by any other party to effectuate the terms and conditions of this Agreement.

[Signature page follows]

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June 11, 2011

Petroleum Development Corporation,

as Managing General Partner of

PDC 2002-D Limited Partnership

1775 Sherman Street Suite 3000

Denver, CO 80203

Attn: Members of the Special Transaction Committee of the Board of Directors

Dear Members of the Committee:

We understand that PDC 2002-D Limited Partnership (the “Limited Partnership”) intends to enter into an Agreement and Plan of Merger (the “Agreement”) by and among the Limited Partnership, Petroleum Development Corporation (in such capacity, the “Acquiror”) and DP 2004 Merger Sub, LLC, a wholly-owned subsidiary of the Acquiror (“Merger Sub”) pursuant to which, among other things, the Limited Partnership will merge with Merger Sub (the “Transaction”) and each outstanding unit (a “Unit”) of interest in the Limited Partnership will be liquidated and automatically converted into the right to receive $4,024 in cash per Unit (the “Consideration”), subject to adjustment as provided in the Agreement.

You have requested that Houlihan Lokey Financial Advisors, Inc. (“Houlihan Lokey”) provide an opinion (the “Opinion”) to the Special Transaction Committee (the “Committee”) of the Board of Directors (the “Board”) of Petroleum Development Corporation, in its capacity as the Managing General Partner of the Limited Partnership (in such capacity, the “Managing General Partner”) as to whether, as of the date hereof, the Consideration to be received by Unaffiliated Holders of Units in the Transaction is fair to such Unaffiliated Holders from a financial point of view. For purposes of this Opinion, “Unaffiliated Holders” means the holders of Units other than the Acquiror and its affiliates.

In connection with this Opinion, we have made such reviews, analyses and inquiries as we have deemed necessary and appropriate under the circumstances. Among other things, we have:

1. reviewed a draft of the Agreement received by us on June 7, 2011;

2. reviewed certain publicly available business and financial information relating to the Limited Partnership that we deemed to be relevant;

3. reviewed certain information relating to the historical, current and future operations, financial condition and prospects of the Limited Partnership made available to us by the Managing General Partner, including (a) financial projections provided to us by the management of the Managing General Partner relating to the Limited Partnership for the remaining life of the Limited Partnership’s wells and (b) certain oil and gas reserve reports prepared by the Managing General Partner’s independent oil and gas reserve engineers (the “Reserve Reports”) containing estimates with respect to the Limited Partnership’s oil and gas reserves;

4. spoken with certain members of the management of the Managing General Partner and members of the Committee and certain of their representatives and advisors regarding the business, operations, financial condition and prospects of the Limited Partnership, the Transaction and related matters;

5. compared the financial and operating performance of the Limited Partnership with that of other public companies that we deemed to be relevant;

245 Park Avenue, 20th Floor • New York, New York 10167 • tel.212.497.4100 • fax.212.661.3070 • www.HL.com

Broker/dealer services through Houlihan Lokey Capital, Inc. Investment advisory services through Houlihan Lokey Financial Advisors, Inc.

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Members of the Special Transaction Committee of the Board of Directors

Petroleum Development Corporation,

as Managing General Partner of

PDC 2002-D Limited Partnership

June 11, 2011

6. considered the publicly available financial terms of certain transactions that we deemed to be relevant;

7. reviewed a certificate addressed to us from senior management of the Managing General Partner which contains, among other things, representations regarding the accuracy of the information, data and other materials (financial or otherwise) provided to or discussed with us by or on behalf of the Managing General Partner and the Limited Partnership; and

8. conducted such other financial studies, analyses and inquiries and considered such other information and factors as we deemed appropriate, including, without limitation, certain alternative oil and gas commodity pricing assumptions and probabilities.

We have relied upon and assumed, without independent verification, the accuracy and completeness of all data, material and other information furnished, or otherwise made available, to us, discussed with or reviewed by us, or publicly available, and do not assume any responsibility with respect to such data, material and other information. In addition, management of the Managing General Partner has advised us, and we have assumed, that the financial projections reviewed by us reflect the best currently available estimates and judgments of such management as to the future financial results and condition of the Limited Partnership, and we express no opinion with respect to such projections or the assumptions on which they are based. With respect to the oil and gas reserve estimates for the Limited Partnership set forth in the Reserve Reports that we have reviewed, the management of the Managing General Partner has advised us, and we have assumed, that such estimates were reasonably prepared on bases reflecting the best currently available estimates and judgments of the Managing General Partner and its independent oil and gas reserve engineers with respect to the oil and gas reserves of the Limited Partnership. With respect to the alternative oil and gas commodity pricing assumptions and probabilities that we have utilized for purposes of our analyses, we have been advised by the management of the Managing General Partner, and we have assumed, that such assumptions are a reasonable basis on which to evaluate the future financial performance of the Limited Partnership and are appropriate for such purposes. We have relied upon and assumed, without independent verification, that there has been no change in the business, assets, liabilities, financial condition, results of operations, cash flows or prospects of the Limited Partnership since the date of the most recent financial statements provided to us that would be material to our analyses or this Opinion, and that there is no information or any facts that would make any of the information reviewed by us incomplete or misleading.

We have relied upon and assumed, without independent verification, that (a) the representations and warranties of all parties to the Agreement and all other related documents and instruments that are referred to therein are true and correct, (b) each party to the Agreement and other related documents and instruments will fully and timely perform all of the covenants and agreements required to be performed by such party, (c) all conditions to the consummation of the Transaction will be satisfied without waiver thereof, and (d) the Transaction will be consummated in a timely manner in accordance with the terms described in the Agreement and other related documents and instruments, without any amendments or modifications thereto that would be material to our analyses. We also have relied upon and assumed, without independent verification, that (i) the Transaction will be consummated in a manner that complies in all respects with all applicable federal and state statutes, rules and regulations, and (ii) all governmental, regulatory, and other consents and approvals necessary for the consummation of the Transaction will be obtained and that no delay, limitations, restrictions or conditions will be imposed or amendments, modifications or waivers made that would have an effect on the Limited Partnership that would be material to our analyses or this Opinion. At the direction of the Committee, this Opinion does not address in any respect adjustments to the Consideration pursuant to the Agreement or otherwise subsequent to the date hereof. In addition, with your consent, we have relied upon and assumed, without independent verification, that the final form of the Agreement will not differ in any respect that would be material to our analyses from the draft of the Agreement identified above.

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Members of the Special Transaction Committee of the Board of Directors

Petroleum Development Corporation,

as Managing General Partner of

PDC 2002-D Limited Partnership

June 11, 2011

Furthermore, in connection with this Opinion, we have not been requested to make, and have not made, any physical inspection or independent appraisal or evaluation of any of the assets, properties or liabilities (fixed, contingent, derivative, off-balance-sheet or otherwise) of the Limited Partnership or any other party, nor were we provided with any such appraisal or evaluation, other than the Reserve Reports. We did not estimate, and express no opinion regarding, the liquidation value of any entity or business. We have undertaken no independent analysis of any potential or actual litigation, regulatory action, possible unasserted claims or other contingent liabilities, to which the Limited Partnership is or may be a party or is or may be subject, or of any governmental investigation of any possible unasserted claims or other contingent liabilities to which the Limited Partnership is or may be a party or is or may be subject. We are not experts in the evaluation of oil and gas reserves and we express no view as to the reserve quantities, or the development or production (including, without limitation, as to the feasibility or timing thereof), of any oil and gas properties of the Limited Partnership.

We have not been requested to, and did not, (a) initiate or participate in any discussions or negotiations with, or solicit any indications of interest from, third parties with respect to the Transaction, the securities, assets, businesses or operations of the Limited Partnership or any other party, or any alternatives to the Transaction, (b) negotiate the terms of the Transaction, or (c) advise the Committee, the Board or any other party with respect to alternatives to the Transaction. This Opinion is necessarily based on financial, economic, market and other conditions as in effect on, and the information made available to us as of, the date hereof. As you are aware, the financial projections and estimates that we have reviewed relating to the future financial performance of the Limited Partnership reflect certain assumptions regarding the oil and gas industry which are subject to significant volatility and which, if different than assumed, could have a material impact on our analyses and opinion. Except as set forth in our engagement letter, we have not undertaken, and are under no obligation, to update, revise, reaffirm or withdraw this Opinion, or otherwise comment on or consider events occurring or coming to our attention after the date hereof.

This Opinion is furnished for the use and benefit of the Committee (solely in its capacity as such) in connection with its consideration of the Transaction and may not be used for any other purpose without our prior written consent. This Opinion should not be construed as creating any fiduciary duty on Houlihan Lokey’s part to any party. This Opinion is not intended to be, and does not constitute, a recommendation to the Committee, the Board, any security holder or any other person as to how to act or vote with respect to any matter relating to the Transaction.

In the ordinary course of business, certain of our affiliates, as well as investment funds in which they may have financial interests, may acquire, hold or sell, long or short positions, or trade or otherwise effect transactions, in debt, equity, and other securities and financial instruments (including loans and other obligations) of, or investments in, the Managing General Partner, the Limited Partnership or any other party that may be involved in the Transaction and their respective affiliates or any currency or commodity that may be involved in the Transaction.

Houlihan Lokey and certain of its affiliates may have in the past provided investment banking, financial advisory and other financial services to the Managing General Partner and other participants in the proposed Transaction and/or certain of their affiliates, for which Houlihan Lokey and such affiliates received compensation. Houlihan Lokey has in the past provided financial advisory services to the Committee in connection with transactions in which the Acquiror is seeking to acquire the outstanding limited partnership interests in other drilling partnerships of which it is the managing general partner and is currently engaged to, among other things, provide financial advisory services to the Committee in connection with other similar transactions. Houlihan Lokey and certain of its affiliates may provide investment banking, financial advisory and other financial services to the Limited Partnership, the Acquiror, other participants in the Transaction or certain of their respective affiliates in the future, for which Houlihan Lokey and such affiliates may receive compensation. In addition, Houlihan Lokey and certain of its affiliates and certain of Houlihan Lokey’s and its affiliates’ respective employees may have invested in or committed to invest in the Limited Partnership, the Acquiror, other participants in the proposed Transaction or certain of their respective affiliates and may do so in the future. Furthermore, in connection with bankruptcies, restructurings, and similar matters, Houlihan Lokey and certain of its affiliates may have in the past acted, may

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Members of the Special Transaction Committee of the Board of Directors

Petroleum Development Corporation,

as Managing General Partner of

PDC 2002-D Limited Partnership

June 11, 2011

currently be acting and may in the future act as financial advisor to debtors, creditors, equity holders, trustees and other interested parties (including, without limitation, formal and informal committees or groups of creditors) that may have included or represented and may include or represent, directly or indirectly, or may have been adverse to, the Managing General Partner, other participants in the Transaction or certain of their respective affiliates, for which advice and services Houlihan Lokey and such affiliates have received and may receive compensation.

We will receive a fee for rendering this Opinion, which is not contingent upon the successful completion of the Transaction. The Managing General Partner has agreed to reimburse certain of our expenses and to indemnify us and certain related parties for certain potential liabilities arising out of our engagement.

Our opinion only addresses the fairness to the Unaffiliated Holders of Units from a financial point of view of the Consideration to be received by such Unaffiliated Holders in the Transaction pursuant to the Agreement and does not address any other aspect or implication of the Transaction or any agreement, arrangement or understanding entered in connection therewith or otherwise. In addition, this Opinion does not express an opinion as to or otherwise address, among other things: (i) the underlying business decision of the Committee, the Board, the Managing General Partner, the Limited Partnership, their respective security holders or any other party to proceed with or effect the Transaction, (ii) the terms of any arrangements, understandings, agreements or documents related to, or the form, structure or any other portion or aspect of, the Transaction or otherwise (other than the Consideration to the extent expressly specified herein), (iii) the fairness of any portion or aspect of the Transaction to the holders of any class of securities, creditors or other constituencies of the Limited Partnership or the Managing General Partner, or to any other party, except as expressly set forth in the last sentence of this Opinion, (iv) the relative merits of the Transaction as compared to any alternative business strategies that might exist for the Limited Partnership, the Managing General Partner or any other party or the effect of any other transaction in which the Limited Partnership, the Managing General Partner or any other party might engage, (v) the fairness of any portion or aspect of the Transaction to any one class or group of the Limited Partnership’s or any other party’s security holders vis-à-vis any other class or group of the Limited Partnership’s or such other party’s security holders (including, without limitation, the allocation of any consideration amongst or within such classes or groups of security holders), (vi) whether or not the Limited Partnership, the Managing General Partner, their respective security holders or any other party is receiving or paying reasonably equivalent value in the Transaction, (vii) the solvency, creditworthiness or fair value of the Limited Partnership or any other participant in the Transaction, or any of their respective assets, under any applicable laws relating to bankruptcy, insolvency, fraudulent conveyance or similar matters, or (viii) the fairness, financial or otherwise, of the amount, nature or any other aspect of any compensation to or consideration payable to or received by any officers, directors or employees of any party to the Transaction, any class of such persons or any other party, relative to the Consideration or otherwise. Furthermore, no opinion, counsel or interpretation is intended in matters that require legal, regulatory, accounting, insurance, tax or other similar professional advice. It is assumed that such opinions, counsel or interpretations have been or will be obtained from the appropriate professional sources. Furthermore, we have relied, with your consent, on the assessments by the Committee, the Board, the Managing General Partner and their respective advisors, as to all legal, regulatory, accounting, insurance and tax matters with respect to the Limited Partnership and the Transaction. The issuance of this Opinion was approved by a committee authorized to approve opinions of this nature.

Based upon and subject to the foregoing, and in reliance thereon, it is our opinion that, as of the date hereof, the Consideration to be received by the Unaffiliated Holders of Units in the Transaction pursuant to the Agreement is fair to such Unaffiliated Holders from a financial point of view.

Very truly yours,

HOULIHAN LOKEY FINANCIAL ADVISORS, INC.

B-5

Chapter 31D West Virginia Business Corporation Act
Article 13 Appraisal Rights
Part I Right to Appraisal and Payment for Shares
W. Va. Code § 31D-13-1301 (2006)

§ 31D-13-1301 Definitions

In this article:

(1) “Affiliate” means a person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with another person or is a senior executive. For purposes of subdivision (4), subsection (b), section one thousand three hundred two [§ 31D-13-1302] of this article, a person is deemed to be an affiliate of its senior executives.

(2) “Beneficial shareholder” means a person who is the beneficial owner of shares held in a voting trust or by a nominee on the beneficial owner’s behalf.

(3) “Corporation” means the issuer of the shares held by a shareholder demanding appraisal and, for matters covered in sections one thousand three hundred twenty-two [§ § 31D-13-1322 through 31D-13-1326, 31D-13-1330 and 31D-13-1331], one thousand three hundred twenty-three, one thousand three hundred twenty-four, one thousand three hundred twenty-five, one thousand three hundred twenty-six, one thousand three hundred thirty and one thousand three hundred thirty-one of this article, includes the surviving entity in a merger.

(4) “Fair value” means the value of the corporation’s shares determined:

(A) Immediately before the effectuation of the corporate action to which the shareholder objects;

(B) Using customary and current valuation concepts and techniques generally employed for similar businesses in the context of the transaction requiring appraisal; and

(C) Without discounting for lack of marketability or minority status except, if appropriate, for amendments to the articles pursuant to subdivision (5), subsection (a), section one thousand three hundred two [§ 31D-13-1302] of this article.

(5) “Interest” means interest from the effective date of the corporate action until the date of payment, at the rate of interest on judgments in this state on the effective date of the corporate action.

(6) “Preferred shares” means a class or series of shares whose holders have preference over any other class or series with respect to distributions.

(7) “Record shareholder” means the person in whose name shares are registered in the records of the corporation or the beneficial owner of shares to the extent of the rights granted by a nominee certificate on file with the corporation.

(8) “Senior executive” means the chief executive officer, chief operating officer, chief financial officer and anyone in charge of a principal business unit or function.

(9) “Shareholder” means both a record shareholder and a beneficial shareholder.

§ 31D-13-1302 Right to appraisal

(a) A shareholder is entitled to appraisal rights, and to obtain payment of the fair value of that shareholder’s shares, in the event of any of the following corporate actions:

(1) Consummation of a merger to which the corporation is a party: (A) If shareholder approval is required for the merger by section one thousand one hundred four [§ 31D-11-1104], article eleven of this chapter and the shareholder is entitled to vote on the merger, except that appraisal rights may not be available to any shareholder of the corporation with respect to shares of any class or series that remain outstanding after consummation of the merger; or (B) if the corporation is a subsidiary and the merger is governed by section one thousand one hundred five [§ 31D-11-1105], article eleven of this chapter;

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(2) Consummation of a share exchange to which the corporation is a party as the corporation whose shares will be acquired if the shareholder is entitled to vote on the exchange, except that appraisal rights may not be available to any shareholder of the corporation with respect to any class or series of shares of the corporation that is not exchanged;

(3) Consummation of a disposition of assets pursuant to section one thousand two hundred two [§ 31D-12-1202], article twelve of this chapter if the shareholder is entitled to vote on the disposition;

(4) An amendment of the articles of incorporation with respect to a class or series of shares that reduces the number of shares of a class or series owned by the shareholder to a fraction of a share if the corporation has the obligation or right to repurchase the fractional share so created; or

(5) Any other amendment to the articles of incorporation, merger, share exchange or disposition of assets to the extent provided by the articles of incorporation, bylaws or a resolution of the board of directors.

(b) Notwithstanding subsection (a) of this section, the availability of appraisal rights under subdivisions (1), (2), (3) and (4), subsection (a) of this section are limited in accordance with the following provisions:

(1) Appraisal rights may not be available for the holders of shares of any class or series of shares which is:

(A) Listed on the New York Stock Exchange or the American Stock Exchange or designated as a national market system security on an interdealer quotation system by the National Association of Securities Dealers, Inc.; or

(B) Not so listed or designated, but has at least two thousand shareholders and the outstanding shares of a class or series has a market value of at least twenty million dollars, exclusive of the value of the shares held by its subsidiaries, senior executives, directors and beneficial shareholders owning more than ten percent of the shares.

(2) The applicability of subdivision (1), subsection (b) of this section is to be determined as of:

(A) The record date fixed to determine the shareholders entitled to receive notice of, and to vote at, the meeting of shareholders to act upon the corporate action requiring appraisal rights; or

(B) The day before the effective date of the corporate action if there is no meeting of shareholders.

(3) Subdivision (1), subsection (b) of this section is not applicable and appraisal rights are to be available pursuant to subsection (a) of this section for the holders of any class or series of shares who are required by the terms of the corporate action requiring appraisal rights to accept for the shares anything other than cash or shares of any class or any series of shares of any corporation, or any other proprietary interest of any other entity, that satisfies the standards set forth in subdivision (1), section (b) of this section at the time the corporate action becomes effective.

(4) Subdivision (1), subsection (b) of this section is not applicable and appraisal rights are to be available pursuant to subsection (a) of this section for the holders of any class or series of shares where any of the shares or assets of the corporation are being acquired or converted, whether by merger, share exchange or otherwise, pursuant to the corporate action by a person, or by an affiliate of a person, who: (A) Is, or at any time in the one-year period immediately preceding approval by the board of directors of the corporate action requiring appraisal rights was, the beneficial owner of twenty percent or more of the voting power of the corporation, excluding any shares acquired pursuant to an offer for all shares having voting power if the offer was made within one year prior to the corporate action requiring appraisal rights for consideration of the same kind and of a value equal to or less than that paid in connection with the corporate action; or (B) for purpose of voting their shares of the corporation, each member of the group formed is deemed to have acquired beneficial ownership, as of the date of the agreement, of all voting shares of the corporation beneficially owned by any member of the group.

(c) Notwithstanding any other provision of section one thousand three hundred two [§ 31D-13-1302] of this article, the articles of incorporation as originally filed or any amendment to the articles of incorporation may limit or eliminate appraisal rights for any class or series of preferred shares, but any limitation or elimination contained in an

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amendment to the articles of incorporation that limits or eliminates appraisal rights for any of the shares that are outstanding immediately prior to the effective date of the amendment or that the corporation is or may be required to issue or sell pursuant to any conversion, exchange or other right existing immediately before the effective date of the amendment does not apply to any corporate action that becomes effective within one year of that date if the action would otherwise afford appraisal rights.

(d) A shareholder entitled to appraisal rights under this article may not challenge a completed corporate action for which appraisal rights are available unless the corporate action:

(1) Was not effectuated in accordance with the applicable provisions of article ten [§ § 31D-10-1001 et seq.], eleven [§ § 31D-11-1101 et seq.] or twelve [§ § 31D-12-1201 et seq.] of this chapter or the corporation’s articles of incorporation, bylaws or board of directors’ resolution authorizing the corporate action; or

(2) Was procured as a result of fraud or material misrepresentation.

§ 31D-13-1303 Assertion of rights by nominees and beneficial owners

(a) A record shareholder may assert appraisal rights as to fewer than all the shares registered in the record shareholder’s name but owned by a beneficial shareholder only if the record shareholder objects with respect to all shares of the class or series owned by the beneficial shareholder and notifies the corporation in writing of the name and address of each beneficial shareholder on whose behalf appraisal rights are being asserted. The rights of a record shareholder who asserts appraisal rights for only part of the shares held of record in the record shareholder’s name under this subsection are to be determined as if the shares as to which the record shareholder objects and the record shareholder’s other shares were registered in the names of different record shareholders.

(b) A beneficial shareholder may assert appraisal rights as to shares of any class or series held on behalf of the shareholder only if the shareholder:

(1) Submits to the corporation the record shareholder’s written consent to the assertion of the rights no later than the date referred to in paragraph (D), subdivision (2), subsection (b), section one thousand three hundred twenty-two [§ 31D-13-1322] of this article; and

(2) Does so with respect to all shares of the class or series that are beneficially owned by the beneficial shareholder.

§ 31D-13-1320 Notice of appraisal rights

(a) If proposed corporate action described in subsection (a), section one thousand three hundred two [§ 31D-13-1302] of this article is to be submitted to a vote at a shareholders’ meeting, the meeting notice must state that the corporation has concluded that shareholders are, are not or may be entitled to assert appraisal rights under this article. If the corporation concludes that appraisal rights are or may be available, a copy of this article must accompany the meeting notice sent to those record shareholders entitled to exercise appraisal rights.

(b) In a merger pursuant to section one thousand one hundred five [§ 31D-11-1105], article eleven of this chapter, the parent corporation must notify in writing all record shareholders of the subsidiary who are entitled to assert appraisal rights that the corporate action became effective. The notice must be sent within ten days after the corporate action became effective and include the materials described in section one thousand three hundred twenty-two [§ 31D-13-1322] of this article.

§ 31D-13-1321 Notice of intent to demand payment

(a) If proposed corporate action requiring appraisal rights under section one thousand three hundred two [§ 31D-13-1302] of this article is submitted to a vote at a shareholders’ meeting, a shareholder who wishes to assert appraisal rights with respect to any class or series of shares:

(1) Must deliver to the corporation before the vote is taken written notice of the shareholder’s intent to demand payment if the proposed action is effectuated; and

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(2) Must not vote, or cause or permit to be voted, any shares of the class or series in favor of the proposed action.

(b) A shareholder who does not satisfy the requirements of subsection (a) of this section is not entitled to payment under this article.

§ 31D-13-1322 Appraisal notice and form

(a) If proposed corporate action requiring appraisal rights under subsection (a), section one thousand three hundred two [§ 31D-13-1302] of this article becomes effective, the corporation must deliver a written appraisal notice and form required by subdivision (1), subsection (b) of this section to all shareholders who satisfied the requirements of section one thousand three hundred twenty-one [§ 31D-13-1321] of this article. In the case of a merger under section one thousand one hundred five [§ 31D-11-1105], article eleven of this chapter, the parent must deliver a written appraisal notice and form to all record shareholders who may be entitled to assert appraisal rights.

(b) The appraisal notice must be sent no earlier than the date the corporate action became effective and no later than ten days after that date and must:

(1) Supply a form that specifies the date of the first announcement to shareholders of the principal terms of the proposed corporate action and requires the shareholder asserting appraisal rights to certify: (A) Whether or not beneficial ownership of those shares for which appraisal rights are asserted was acquired before that date; and (B) that the shareholder did not vote for the transaction;

(2) State:

(A) Where the form must be sent and where certificates for certificated shares must be deposited and the date by which those certificates must be deposited, which date may not be earlier than the date for receiving the required form under this subdivision;

(B) A date by which the corporation must receive the form which date may not be fewer than forty nor more than sixty days after the date the appraisal notice and form required by subsection (a) of this section are sent and state that the shareholder is deemed to have waived the right to demand appraisal with respect to the shares unless the form is received by the corporation by the specified date;

(D) That, if requested in writing, the corporation will provide, to the shareholder so requesting, within ten days after the date specified in paragraph (B) of this subdivision the number of shareholders who return the forms by the specified date and the total number of shares owned by them; and

(E) The date by which the notice to withdraw under section one thousand three hundred twenty-three [§ 31D-13-1323] of this article must be received, which date must be within twenty days after the date specified in paragraph (B) of this subdivision; and

(3) Be accompanied by a copy of this article.

§ 31D-13-1323 Perfection of rights; right to withdraw

(a) A shareholder who receives notice pursuant to section one thousand three hundred twenty-two [§ 31D-13-1322] of this article and who wishes to exercise appraisal rights must certify on the form sent by the corporation whether the beneficial owner of the shares acquired beneficial ownership of the shares before the date required to be set forth in the notice pursuant to subdivision (1), subsection (b), section one thousand three hundred twenty-two of this article. If a shareholder fails to make this certification, the corporation may elect to treat the shareholder’s shares as after-acquired shares under section one thousand three hundred twenty-five [§ 31D-13-1325] of this article. In addition, a shareholder who wishes to exercise appraisal rights must execute and return the form and, in the case of certificated shares, deposit the shareholder’s certificates in accordance with the terms of the notice by the date referred to in the notice pursuant to paragraph (B), subdivision (2), subsection (b), section one thousand three hundred twenty-two of this article. Once a shareholder deposits the shareholder’s certificates or, in the case of

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uncertificated shares, returns the executed forms, that shareholder loses all rights as a shareholder unless the shareholder withdraws pursuant to subsection (b) of this section.

(b) A shareholder who has complied with subsection (a) of this section may decline to exercise appraisal rights and withdraw from the appraisal process by so notifying the corporation in writing by the date set forth in the appraisal notice pursuant to paragraph (E), subdivision (2), subsection (b), section one thousand three hundred twenty-two [§ 31D-13-1322] of this article. A shareholder who fails to withdraw from the appraisal process by that date may not withdraw without the corporation’s written consent.

(c) A shareholder who does not execute and return the form and, in the case of certificated shares, deposit the shareholder’s share certificates where required, each by the date set forth in the notice described in subsection (b), section one thousand three hundred twenty-two [§ 31D-13-1322] of this article, is not entitled to payment under this article.

§ 31D-13-1324 Payment

(a) Except as provided in section one thousand three hundred twenty-five [§ 31D-13-1325] of this article, within thirty days after the form required by paragraph (B), subdivision (2), subsection (b), section one thousand three hundred twenty-two [§ 31D-13-1322] of this article is due, the corporation shall pay in cash to those shareholders who complied with subsection (a), section one thousand three hundred twenty-three [§ 31D-13-1323] of this article the amount the corporation estimates to be the fair value of their shares, plus interest.

(b) The payment to each shareholder pursuant to subsection (a) of this article must be accompanied by:

(1) Financial statements of the corporation that issued the shares to be appraised, consisting of a balance sheet as of the end of a fiscal year ending not more than sixteen months before the date of payment, an income statement for that year, a statement of changes in shareholders’ equity for that year and the latest available interim financial statements, if any;

(2) A statement of the corporation’s estimate of the fair value of the shares, which estimate must equal or exceed the corporation’s estimate given pursuant to paragraph (C), subdivision (2), subsection (b), section one thousand three hundred twenty-two [§ 31D-13-1322] of this article; and

(3) A statement that shareholders described in subsection (a) of this section have the right to demand further payment under section one thousand three hundred twenty-six [§ 31D-13-1326] of this article and that if any shareholder does not make a demand for further payment within the time period specified, shareholder is deemed to have accepted the payment in full satisfaction of the corporation’s obligations under this article.

§ 31D-13-1325 After-acquired shares

(a) A corporation may elect to withhold payment required by section one thousand three hundred twenty-four [§ 31D-13-1324] of this article from any shareholder who did not certify that beneficial ownership of all of the shareholder’s shares for which appraisal rights are asserted was acquired before the date set forth in the appraisal notice sent pursuant to subdivision (1), subsection (b), section one thousand three hundred twenty-two [§ 31D-13-1322] of this article.

(b) If the corporation elected to withhold payment under subsection (a) of this section, it must, within thirty days after the form required by paragraph (B), subdivision (2), subsection (b), section one thousand three hundred twenty-two [§ 31D-13-1322] of this article is due, notify all shareholders who are described in subsection (a) of this section:

(1) Of the information required by subdivision (1), subsection (b), section one thousand three hundred twenty-four [§ 31D-13-1324] of this article;

(2) Of the corporation’s estimate of fair value pursuant to subdivision (2), subsection (b), section one thousand three hundred twenty-four [§ 31D-13-1324] of this article;

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(3) That they may accept the corporation’s estimate of fair value, plus interest, in full satisfaction of their demands or demand appraisal under section one thousand three hundred twenty-six [§ 31D-13-1326] of this article;

(4) That those shareholders who wish to accept the offer must notify the corporation of their acceptance of the corporation’s offer within thirty days after receiving the offer; and

(5) That those shareholders who do not satisfy the requirements for demanding appraisal under section one thousand three hundred twenty-six [§ 31D-13-1326] of this article are deemed to have accepted the corporation’s offer.

(c) Within ten days after receiving the shareholder’s acceptance pursuant to subsection (b) of this section, the corporation must pay in cash the amount it offered under subdivision (2), subsection (b) of this section to each shareholder who agreed to accept the corporation’s offer in full satisfaction of the shareholder’s demand.

(d) Within forty days after sending the notice described in subsection (b) of this section, the corporation must pay in cash the amount it offered to pay under subdivision (2), subsection (b) of this section to each shareholder described in subdivision (5), subsection (b) of this section.

§ 31D-13-1326 Procedure if shareholder dissatisfied with payment or offer

(a) A shareholder paid pursuant to section one thousand three hundred twenty-four [§ 31D-13-1324] of this article who is dissatisfied with the amount of the payment must notify the corporation in writing of that shareholder’s estimate of the fair value of the shares and demand payment of that estimate plus interest and less any payment due under section one thousand three hundred twenty-four of this article. A shareholder offered payment under section one thousand three hundred twenty-five [§ 31D-13-1325] of this article who is dissatisfied with that offer must reject the offer and demand payment of the shareholder’s stated estimate of the fair value of the shares plus interest.

(b) A shareholder who fails to notify the corporation in writing of that shareholder’s demand to be paid the shareholder’s stated estimate of the fair value plus interest under subsection (a) of this section within thirty days after receiving the corporation’s payment or offer of payment under sections one thousand three hundred twenty-four [§ 31D-13-1324] or one thousand three hundred twenty-five [§ 31D-13-1325] of this article, respectively, waives the right to demand payment under this section and is entitled only to the payment made or offered pursuant to those respective sections.

§ 31D-13-1330 Court action

(a) If a shareholder makes demand for payment under section one thousand three hundred twenty-six [§ 31D-13-1326] of this article which remains unsettled, the corporation shall commence a proceeding within sixty days after receiving the payment demand and petition the court to determine the fair value of the shares and accrued interest. If the corporation does not commence the proceeding within the sixty-day period, it shall pay in cash to each shareholder the amount the shareholder demanded pursuant to section one thousand three hundred twenty-six of this article plus interest.

(b) The corporation shall make all shareholders, whether or not residents of this state, whose demands remain unsettled parties to the proceeding as in an action against their shares, and all parties must be served with a copy of the petition. Nonresidents may be served by registered or certified mail or by publication as provided by law.

(c) The jurisdiction of the court in which the proceeding is commenced is plenary and exclusive. The court may appoint one or more persons as appraisers to receive evidence and recommend a decision on the question of fair value. The appraisers have the powers described in the order appointing them, or in any amendment to it. The shareholders demanding appraisal rights are entitled to the same discovery rights as parties in other civil proceedings. There is no right to a jury trial.

(d) Each shareholder made a party to the proceeding is entitled to judgment: (1) For the amount, if any, by which the court finds the fair value of the shareholder’s shares, plus interest, exceeds the amount paid by the corporation to the shareholder for the shares; or (2) for the fair value, plus interest, of the shareholder’s shares for

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which the corporation elected to withhold payment under section one thousand three hundred twenty-five [§ 31D-13-1325] of this article.

§ 31D-13-1331 Court costs and counsel fees

(a) The court in an appraisal proceeding commenced under section one thousand three hundred thirty [§ 31D-13-1330] of this article shall determine all costs of the proceeding, including the reasonable compensation and expenses of appraisers appointed by the court. The court shall assess the costs against the corporation, except that the court may assess costs against all or some of the shareholders demanding appraisal, in amounts the court finds equitable, to the extent the court finds the shareholders acted arbitrarily, vexatiously, or not in good faith with respect to the rights provided by this article.

(b) The court in an appraisal proceeding may also assess the fees and expenses of counsel and experts for the respective parties, in amounts the court finds equitable:

(1) Against the corporation and in favor of any or all shareholders demanding appraisal if the court finds the corporation did not substantially comply with the requirements of section one thousand three hundred twenty [§ 31D-13-1320], one thousand three hundred twenty-two [§ 31D-13-1322], one thousand three hundred twenty-four [§ 31D-13-1324] or one thousand three hundred twenty-five [§ 31D-13-1325], of this article; or

(2) Against either the corporation or a shareholder demanding appraisal, in favor of any other party, if the court finds that the party against whom the fees and expenses are assessed acted arbitrarily, vexatiously or not in good faith with respect to the rights provided by this article.

(c) If the court in an appraisal proceeding finds that the services of counsel for any shareholder were of substantial benefit to other shareholders similarly situated, and that the fees for those services should not be assessed against the corporation, the court may award to counsel reasonable fees to be paid out of the amounts awarded the shareholders who were benefited.

(d) To the extent the corporation fails to make a required payment pursuant to section one thousand three hundred twenty-four [§ 31D-13-1324], one thousand three hundred twenty-five [§ 31D-13-1325], or one thousand three hundred twenty-six [§ 31D-13-1326] of this article, the shareholder may sue directly for the amount owed and, to the extent successful, are to be entitled to recover from the corporation all costs and expenses of the suit, including counsel fees.

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Petroleum Development Corporation

February 2, 2011

FAX (303) 623-4258

621 SEVENTEENTH STREET SUITE 1550 DENVER, COLORADO 80293 TELEPHONE 303) 623-9147

February 2, 2011

Petroleum Development Corporation

120 Genesis Boulevard

Bridgeport, West Virginia 26330

Gentlemen:

At your request, we have prepared an estimate of the reserves, future production, and income attributable to certain leasehold and royalty interests of Petroleum Development Corporation’s (“PDC”) 2002D Partnership as of December 31, 2010. The subject properties are located in the state of Colorado. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study completed on February 2, 2011 and presented herein, was prepared for public disclosure by PDC in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott account for a portion of PDC2002D’s total net proved reserves as of December 31, 2010. The third party estimate conducted by Ryder Scott addresses 100 percent of the total proved developed net liquid hydrocarbon reserves, 100 percent of the total proved developed net gas reserves, 100 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 100 percent of the total proved undeveloped net gas reserves of PDC2002D.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2010 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually

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Petroleum Development Corporation

February 2, 2011

recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
Petroleum Development Corporation Partnership: 2002D
As of December 31, 2010


	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved

*Net Remaining Reserves*
Oil/Condensate — Barrels		58,138		0		249,715		307,853
Plant Products — Barrels		24,932		0		90,919		115,851
Gas — MMCF		613		0		1,803		2,416

*Income Data M$*
Future Gross Revenue	$	7,046	$	0	$	26,762	$	33,808
Deductions		4,100		0		12,715		16,815

Future Net Income (FNI)	$	2,946	$	0	$	14,047	$	16,993

Discounted FNI @ 10%	$	2,056	$	0	$	5,289	$	7,345

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries^tm System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton. The program was used solely at the request of PDC. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 76 percent and gas reserves account for the remaining 24 percent of total future gross revenue from proved reserves.

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Petroleum Development Corporation

February 2, 2011

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.


	Discounted Future Net Income M$
	As of December 31, 2010
Discount Rate	Total
Percent	Proved

5	$	10,780
15	$	5,286
20	$	3,972
25	$	3,091

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes included herein do not attribute gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At PDC’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

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Petroleum Development Corporation

February 2, 2011

PDC’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which PDC 2002D Partnership owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. The reserve evaluator must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods or analogy. Approximately 100 percent of the proved producing reserves attributable to producing wells were estimated by performance methods. The performance method utilized was decline curve analysis which utilized extrapolations of historical production data. The data utilized in this analysis were supplied to Ryder Scott by PDC or obtained from public data sources and were considered sufficient for the purpose thereof.

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Petroleum Development Corporation

February 2, 2011

Approximately 100 percent of the proved undeveloped reserves included herein were estimated by the analogy method. The data utilized from the existing producing wells to develop analogues were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

PDC has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by PDC with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, well logs, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data supplied by PDC. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by PDC. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity

D-6

Petroleum Development Corporation

February 2, 2011

and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

PDC furnished us with the above mentioned average prices in effect on December 31, 2010. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by PDC. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by PDC to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.


Geographic		Price	Avg Benchmark	Avg Realized
Area	Product	Reference	Prices	Prices

United States	Oil/Condensate	WTI Cushing	$79.43/Bbl	$71.42/Bbl
	NGLs	WTI Cushing	$79.43/Bbl	$34.10/Bbl
	Gas	Henry Hub NYMEX	$4.38/MMBTU	$3.30/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report are based on the operating expense reports of PDC and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by PDC. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by PDC and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual

D-7

Petroleum Development Corporation

February 2, 2011

data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by PDC were accepted without independent verification.

The proved undeveloped reserves in this report have been incorporated herein in accordance with PDC’s plans to develop these reserves as of December 31, 2010. The implementation of PDC’s development plans as presented to us and incorporated herein is subject to the approval process adopted by PDC’s management. As the result of our inquires during the course of preparing this report, PDC has informed us that the development activities included herein have been subjected to and received the internal approvals required by PDC’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to PDC. Additionally, PDC has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by PDC were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to PDC2002D. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by PDC.

D-8

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Larry Thomas Nelms is the primary technical person responsible for the estimate of the reserves, future production and income.

Nelms, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1983, is a Managing Senior Vice President and also serves as a member of the Board of Directors, responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Nelms served in a number of engineering positions with Dome Petroleum, Mizel Petro Resources and Exxon. For more information regarding Mr. Nelms’ geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Nelms earned a Bachelor of Science degree in Mechanical Engineering from Mississippi State University in 1963 and a Master of Science from the University of New Mexico in 1965, and he is a registered Professional Engineer in the State of Colorado. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers, where he serves as chairman of the Denver Section and also served for three years on the board of directors.

As part of his 2009 continuing education hours, Nelms attended an internally presented 16 hours of formalized training as well as the day long 2009 RSC Reserves Conference forum, and a presentation at the Denver Section of SPEE by Dr. John Lee relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register. Nelms serves as the instructor of the PetroSkills course entitled “Oil & Gas Reserve Evaluation” for a period of four years.

Based on his educational background, professional training and more than 25 years of practical experience in the estimation and evaluation of petroleum reserves, Nelms has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

D-10

Financial Statements (unaudited)

PDC 2002-D Limited Partnership

Condensed Balance Sheets

(Unaudited)


	June 30,			December 31,
	2011			2010*

ASSETS
Current assets:
Cash and cash equivalents	$	8,315		$	133,238
Accounts receivable		109,929			133,783
Crude oil inventory		39,987			40,211
Due from Managing General Partner-derivatives		375,197			345,618

Total current assets		533,428			652,850

Natural gas and crude oil properties, successful efforts method, at cost		16,326,233			16,301,661
Less: Accumulated depreciation, depletion and amortization		(10,643,605	)		(10,238,283	)

Natural gas and crude oil properties, net		5,682,628			6,063,378

Due from Managing General Partner-derivatives		447,156			556,021
Other assets		95,800			86,464

Total noncurrent assets		6,225,584			6,705,863

Total Assets	$	6,759,012		$	7,358,713


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	12,537		$	40,662
Due to Managing General Partner-derivatives		303,401			297,142
Due to Managing General Partner-other, net		330,882			587,730

Total current liabilities		646,820			925,534

Due to Managing General Partner-derivatives		321,548			420,505
Asset retirement obligations		465,297			451,630

Total liabilities		1,433,665			1,797,669

Commitments and contingent liabilities
Partners’ equity:
Managing General Partner		1,263,156			1,306,336
Limited Partners — 1,455.26 units issued and outstanding		4,062,191			4,254,708

Total Partners’ equity		5,325,347			5,561,044

Total Liabilities and Partners’ Equity	$	6,759,012		$	7,358,713


*		Derived from audited 2010 balance sheet

See accompanying notes to unaudited condensed financial statements.

E-3

PDC 2002-D Limited Partnership

Condensed Statements of Operations

(Unaudited)


						Six Months Ended
	Three Months Ended June 30,					June 30,
	2011		2010			2011			2010

Revenues:
Natural gas, NGLs and crude oil sales	$	327,134	$	323,102		$	690,973		$	727,436
Commodity price risk management gain, net		98,152		155,864			42,746			617,889

Total revenues		425,286		478,966			733,719			1,345,325

Operating costs and expenses:
Natural gas, NGLs and crude oil production costs		121,324		323,226			274,212			734,672
Direct costs — general and administrative		40,013		4,917			235,970			6,915
Depreciation, depletion and amortization		196,534		275,553			405,322			557,099
Accretion of asset retirement obligations		6,885		6,483			13,667			12,873

Total operating costs and expenses		364,756		610,179			929,171			1,311,559

Income (loss) from operations		60,530		(131,213	)		(195,452	)		33,766
Interest income		28		46			77			93

Net income (loss)	$	60,558	$	(131,167	)	$	(195,375	)	$	33,859

Net income (loss) allocated to partners	$	60,558	$	(131,167	)	$	(195,375	)	$	33,859
Less: Managing General Partner interest in net income (loss)		12,112		(26,233	)		(39,075	)		6,772

Net income (loss) allocated to Investor Partners	$	48,446	$	(104,934	)	$	(156,300	)	$	27,087

Net income (loss) per Investor Partner unit	$	33	$	(72	)	$	(107	)	$	19

Investor Partner units outstanding		1,455.26		1,455.26			1,455.26			1,455.26

See accompanying notes to unaudited condensed financial statements.

E-4

PDC 2002-D Limited Partnership

Condensed Statements of Cash Flows

(unaudited)


	Six Months Ended
	June 30,
	2011			2010

Cash flows from operating activities:
Net income (loss)	$	(195,375	)	$	33,859
Adjustments to net income (loss) to reconcile to net cash provided by operating activities:
Depreciation, depletion and amortization		405,322			557,099
Accretion of asset retirement obligations		13,667			12,873
Unrealized gain on derivative transactions		(13,412	)		(407,875	)
Changes in operating assets and liabilities:
Decrease in accounts receivable		23,854			19,002
Decrease (increase) in crude oil inventory		224			(3,875	)
Increase in other assets		(9,336	)		(9,370	)
Increase (decrease) in accounts payable and accrued expenses		(28,125	)		184,978
Increase (decrease) in Due to Managing General Partner — other, net		(256,848	)		223,492
Decrease in Due from Managing General Partner — other, net		—			54,375

Net cash provided by (used in) operating activities		(60,029	)		664,558

Cash flows from investing activities:
Capital expenditures for natural gas and crude oil properties		(24,572	)		(25,003	)

Net cash used in investing activities		(24,572	)		(25,003	)

Cash flows from financing activities:
Distributions to Partners		(40,322	)		(639,462	)

Net cash used in financing activities		(40,322	)		(639,462	)

Net increase (decrease) in cash and cash equivalents		(124,923	)		93
Cash and cash equivalents, beginning of period		133,238			125,978

Cash and cash equivalents, end of period		8,315			126,071

See accompanying notes to unaudited condensed financial statements.

E-5

PDC 2002-D Limited Partnership

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
June 30, 2011
(UNAUDITED)

Note 1 — General and Basis of Presentation

PDC 2002-D Limited Partnership (the “Partnership” or the “Registrant”) was organized as a limited partnership, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of natural gas and crude oil properties. Business operations of the Partnership commenced upon closing of an offering for the sale of Partnership units. Upon funding, the Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner which authorizes Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, to conduct and manage the Partnership’s business. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner is authorized to manage all activities of the Partnership and initiates and completes substantially all Partnership transactions.

As of June 30, 2011, there were 1,032 Investor Partners. PDC is the designated Managing General Partner of the Partnership and owns a 20% Managing General Partner ownership in the Partnership. According to the terms of the Agreement, revenues, costs and cash distributions of the Partnership are allocated 80% to the limited partners (“Investor Partners”), which are shared pro rata, based upon the number of units in the Partnership, and 20% to the Managing General Partner. The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual Investor Partner. Through June 30, 2011, the Managing General Partner has repurchased 143.1 units of Partnership interests from the Investor Partners at an average price of $5,360 per unit. As of June 30, 2011, the Managing General Partner owns 27.9% of the Partnership.

Beginning in April 2009, when the average Investor Partner’s annual rate of return fell below 12.8%, a condition of obligation arose subject to Section 4.02 Distributions, of the Agreement. Pursuant to the Performance Standard Obligation provision, which expires in June 2013, the Partnership modified the distribution rate of cash distributions from that described in the previous paragraph, between the Managing General Partner and the Investor Partners. During the six months ended June 30, 2011 and 2010, distributions paid to the Managing General Partner were reduced and distributions to the Investor Partners were increased by $3,959 and $65,296, respectively as a result of the Preferred Cash Distribution made under the terms in Section 4.02. For more information concerning the Performance Standard Obligation, see Note 8, Partners’ Equity and Cash Distributions to the Partnership financial statements that accompany the 2010 Form 10-K.

The Partnership expects continuing operations of its natural gas and crude oil properties until such time the Partnership’s wells are depleted or become uneconomical to produce, at which time they may be sold or plugged, reclaimed and abandoned. The Partnership’s maximum term of existence extends through December 31, 2050, unless dissolved by certain conditions stipulated within the Agreement which are unlikely to occur at this time, or by written consent of the Investor Partners owning a majority of outstanding units at that time.

In the Managing General Partner’s opinion, the accompanying interim unaudited condensed financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary for a fair statement of the Partnership’s financial statements for interim periods in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities and Exchange Commission (“SEC”). Accordingly, pursuant to such rules and regulations, certain notes and other financial information included in the audited financial statements have been condensed or omitted. The information presented in this quarterly report on Form 10-Q should be read in conjunction with the Partnership’s audited financial statements and notes thereto included in the Partnership’s 2010 Form 10-K. The Partnership’s accounting policies are described in the Notes to Financial Statements in the Partnership’s 2010 Form 10-K and updated, as necessary, in this Form 10-Q. The results of operations for the three and six months ended June 30, 2011, and the cash flows for the same periods, are not necessarily indicative of the results to be expected for the full year or any other future period.

E-6

PDC 2002-D Limited Partnership

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)
June 30, 2011
(UNAUDITED)

Certain reclassifications have been made to correct the prior period disclosures to conform to the current year presentation, specifically related to the fair value level classification of certain derivative instruments. The reclassification had no impact on the Partnership’s previously reported financial position, cash flows, net income or partners’ equity. See Note 4, Fair Value Measurements and Disclosures, for additional information regarding the fair value classification of the Partnership’s natural gas and crude oil derivative instruments.

On June 20, 2011, the Partnership, PDC and its wholly-owned subsidiary, DP 2004 Merger Sub, LLC (“DP Merger Sub”), a Delaware limited liability company, entered into an agreement and plan of merger (the “Merger Agreement”), in which PDC seeks to acquire the Partnership, subject to the vote and approval of a majority of the limited partnership units held, by Investor Partners of the Partnership, other than PDC and its affiliates (“non-affiliated investor partners”). Pending the outcome of the proposed Merger Agreement, the Managing General Partner suspended, as of April 7, 2011, the opportunity for an individual non-affiliated investor partner to request that PDC repurchase their respective limited partnership units. For more information on the proposed Merger Agreement, see Note 3, Transactions with Managing General Partner and Affiliates- Proposed Merger with PDC and DP 2004 Merger Sub, LLC, which follows.

Note 2 — Recent Accounting Standards

Recently Adopted Accounting Standards

Fair Value Measurements and Disclosures

In January 2010, the Financial Accounting Standards Board (“FASB”) issued changes related to fair value measurements requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements. These changes were effective for the Partnership’s financial statements issued for annual reporting periods, and for interim reporting periods within the year, beginning after December 15, 2010. The adoption of this change did not have a material impact on the Partnership’s financial statements.

Recently Issued Accounting Standards

Fair Value Measurement

On May 12, 2011, the FASB issued changes related to fair value measurement. The changes represent the converged guidance of the FASB and the International Accounting Standards Board (“IASB”) (collectively the “Boards”) on fair value measurement. Many of the changes eliminate unnecessary wording differences between International Financial Reporting Standards (“IFRS”) and U.S. GAAP. The changes expand existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs. In addition, the changes also require the categorization by level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position whose fair value must be disclosed. These changes are to be applied prospectively and are effective for public entities during interim and annual periods beginning after December 15, 2011. Early application is not permitted. With the exception of the disclosure requirements, the adoption of these changes is not expected to have a significant impact on the Partnership’s financial statements.

Note 3 — Transactions with Managing General Partner and Affiliates

The Managing General Partner transacts business on behalf of the Partnership under the authority of the D&O Agreement. Revenues and other cash inflows received on behalf of the Partnership are distributed to the Partners net

E-7

PDC 2002-D Limited Partnership

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)
June 30, 2011
(UNAUDITED)

of (after deducting) corresponding operating costs and other cash outflows incurred on behalf of the Partnership. The fair value of the Partnership’s portion of unexpired derivative instruments is recorded on the condensed balance sheets under the captions “Due from Managing General Partner-derivatives,” in the case of net unrealized gains or “Due to Managing General Partner-derivatives,” in the case of net unrealized losses.

The following table presents transactions with the Managing General Partner reflected in the condensed balance sheet line item — “Due from (to) Managing General Partner-other, net,” which remain undistributed or unsettled with the Partnership’s investors as of the dates indicated.


	June 30,			December 31,
	2011			2010

Natural gas, NGLs and crude oil sales revenues collected from the Partnership’s third-party customers	$	104,264		$	83,892
Commodity price risk management, realized gain		9,509			48,073
Other⁽¹⁾		(444,655	)		(719,695	)

Total Due to Managing General Partner-other, net	$	(330,882	)	$	(587,730	)


(1)		All other unsettled transactions, excluding derivative instruments, between the Partnership and the Managing General Partner. The majority of these are operating costs or general and administrative costs which have not been deducted from distributions.

The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note 5, Derivative Financial Instruments, with the Managing General Partner and its affiliates for the three and six months ended June 30, 2011 and 2010. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Natural gas, NGLs and crude oil production costs” line item on the condensed statements of operations.


	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010

Well operations and maintenance	$	94,617	$	296,167	$	219,577	$	675,540
Gathering, compression and processing fees		11,018		11,415		21,763		23,501
Direct costs — general and administrative		40,013		4,917		235,970		6,915
Cash distributions ⁽¹⁾⁽²⁾		3,776		26,973		7,637		116,669


(1)		Cash distributions include $1,744 and $3,532 during the three and six months ended June 30, 2011, respectively, and $15,135 and $54,072 during the three and six months ended June 30, 2010, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.


(2)		Cash distributions to the Managing General Partner were reduced by $1,922 and $3,959 during the three and six months ended June 30, 2011, respectively, and $22,802 and $65,296 for the three and six months ended June 20, 2010, respectively, due to Preferred Cash Distributions made by the Managing General Partner to Investor Partners under the Performance Standard Obligation provision of the Agreement. For more information concerning this obligation, see Note 1, General and Basis of Presentation.

Proposed Merger with PDC and DP 2004 Merger Sub, LLC

On June 20, 2011, the Partnership, PDC and DP Merger Sub entered into the Merger Agreement, in which PDC seeks to acquire the Partnership, subject to the vote and approval of a majority of the limited partnership units held by non-affiliated investor partners. Pursuant to the Merger Agreement, if the merger is approved by the holders of a

E-8

PDC 2002-D Limited Partnership

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)
June 30, 2011
(UNAUDITED)

majority of the limited partnership units held by the non-affiliated investor partners of the Partnership, as well as, the satisfaction of other customary closing conditions, then the Partnership will merge with and into DP Merger Sub, the separate existence of the Partnership will terminate and the non-affiliated investor partners will have the right to receive cash payments in the aggregate amount of $5,280,132 or $4,024 per limited partnership unit, subject to any adjustments made to the merger consideration for certain increases in commodity prices between the date of signing the merger agreement and the filing of the definitive proxy statement, plus the sum of the amounts withheld, if any, from per unit cash distributions by the Partnership from October 1, 2010 through August 31, 2011 for the Partnership’s Additional Codell Formation Development Plan, less the sum of the per unit cash distributions made after August 31, 2011 and before the transaction closes. DP Merger Sub shall be the surviving entity of the merger and shall be wholly-owned by PDC, and the limited partners will have no continuing interest in the Partnership, since the Partnership will cease as a separate business entity. The merger will become effective following the filing of a certificate of merger with the Secretaries of State of West Virginia and Delaware as soon as practicable after the last condition precedent to the merger has been satisfied, or waived. Following consummation of the merger, the non-affiliated investor partners will no longer participate in the Partnership’s future earnings or any further economic benefit.

The Merger Agreement has been approved by PDC’s Board of Directors (the “Board”); PDC, as sole member of the DP Merger Sub; and by the Special Committee formed by the Board, comprised of four directors of PDC who are not officers or employees of the Partnership or PDC and have no economic interest in the Partnership, to represent the interests of the non-affiliated investor partners holding limited partnership units.

The Merger Agreement among the Partnership, PDC and its subsidiary DP Merger Sub, may be terminated, and the merger abandoned:


	•	should all parties agree by mutual consent to terminate the Merger Agreement;


	•	by any party thereto, should the proposed merger not occur by December 15, 2011;


	•	by any party thereto, should consummation of the merger become illegal or be otherwise prohibited by law or regulation;


	•	by any party thereto, should any suit or action be pending against parties to the Merger Agreement challenging the legality or any aspect of the merger transaction;


	•	by the Special Committee, on behalf of the Partnership and prior to approval by non-affiliated investor partners, should the Special Committee believe it has received a superior offer that is more favorable to the non-affiliated investor partners; or


	•	by PDC or the Partnership, should either PDC or the Partnership fail to perform its obligations under the Merger Agreement and such failure has a non-curable material adverse effect on PDC or the Partnership, respectively, or materially and adversely affects the transactions contemplated by the Merger Agreement.

On June 23, 2011, the Partnership filed a preliminary proxy statement on Schedule 14A relating to the merger with the SEC. Although there is no assurance of the likelihood or timing of the merger transaction, upon clearance by the SEC, a definitive proxy statement will be mailed to the Partnership’s limited partners. Closing of the merger is conditioned on approval by a majority vote of non-affiliated investor partners on both proposals to (1) amend the limited partnership agreement to expressly provide non-affiliated investor partners the right to approve merger transactions and (2) approve the Merger Agreement, as described above. If approved by a majority vote of non-affiliated investor partners and after the filing of a certificate of merger with the Secretaries of State of West Virginia and Delaware, no additional filing or registration with, notification to, or authorization, consent or approval of, any governmental entity will be required in connection with the execution and delivery of the Merger Agreement by the Partnership, PDC or DP Merger Sub or the consummation by the Partnership, PDC or DP Merger Sub of the

E-9

PDC 2002-D Limited Partnership

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)
June 30, 2011
(UNAUDITED)

transactions contemplated thereby. Following consummation of the merger, the non-affiliated investor partners will no longer participate in the Partnership’s future earnings or any further economic benefit.

Regardless of whether the merger is consummated, all costs and expenses incurred by PDC, the Partnership and DP Merger Sub in connection with the Merger Agreement shall be paid by PDC.

Note 4 — Fair Value Measurements and Disclosures

Derivative Financial Instruments

Determination of fair value. Fair value accounting standards have established a fair value hierarchy that prioritizes the inputs used in applying a valuation methodology. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:

Level 1 — Quoted prices (unadjusted) in active markets for identical assets or liabilities.

Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means.

Level 3 — Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.

E-10

PDC 2002-D Limited Partnership

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)
June 30, 2011
(UNAUDITED)

The following table presents, for each hierarchy level, the Partnership’s derivative assets and liabilities, both current and non-current portions, measured at fair value on a recurring basis.


	June 30, 2011								December 31, 2010^(a)
	Level 2^(b)			Level 3^(c)		Total			Level 2^(b)			Level 3^(c)		Total

Assets:
Commodity based derivatives	$	812,328		$	10,025	$	822,353		$	867,993		$	33,646	$	901,639

Total assets		812,328			10,025		822,353			867,993			33,646		901,639

Liabilities:
Commodity based derivatives		(49,398	)		—		(49,398	)		(84,806	)		—		(84,806	)
Basis protection derivative contracts		(575,551	)		—		(575,551	)		(632,841	)		—		(632,841	)

Total liabilities		(624,949	)		—		(624,949	)		(717,647	)		—		(717,647	)

Net asset	$	187,379		$	10,025	$	197,404		$	150,346		$	33,646	$	183,992


(a)		The Partnership reclassified its NYMEX-based natural gas fixed-price swaps from Level 1 to Level 2 (decreasing the previously reported net asset in Level 1 by approximately $868,000) and CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability in Level 3 by approximately $718,000). The amounts presented reflect these reclassifications and conform to current period presentation.


(b)		Includes the Partnership’s fixed-price swaps and basis swaps.


(c)		Includes the Partnership’s natural gas collars.

The following table presents a reconciliation of the Partnership’s Level 3 fair value measurements.


	Six Months Ended
	June 30,			June 30,
	2011			2010⁽¹⁾

Fair value, net asset, beginning of period	$	33,646		$	72,357
Changes in fair value included in statement of operations line item:
Commodity price risk management, net		(52,486	)		(111,325	)
Settlements		28,865			72,910

Fair value, net asset, end of period	$	10,025		$	33,942

Change in unrealized gain (loss) relating to assets (liabilities) still held as of June 30, 2011 and 2010, respectively, included in statement of operations line item:
Commodity price risk management, net	$	1,017		$	27,346


(1)		The Partnership reclassified its CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability at the beginning of the period by approximately $641,000). The amounts presented reflect these reclassifications and conform to current period presentation.

See Note 5, Derivative Financial Instruments, for additional disclosure related to the Partnership’s derivative financial instruments.

E-11

PDC 2002-D Limited Partnership

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)
June 30, 2011
(UNAUDITED)

Non-Derivative Financial Assets and Liabilities

The carrying values of the financial instruments comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments.

Note 5 — Derivative Financial Instruments

As of June 30, 2011, the Partnership had derivative instruments in place for a portion of its anticipated production through 2013 for a total of 399,408 MMbtu of natural gas and 1,960 Bbl of crude oil.

The following table presents the location and fair value amounts of the Partnership’s derivative instruments on the accompanying condensed balance sheets. These derivative instruments were comprised of commodity collars, commodity fixed-price swaps and basis swaps.


			Fair Value
		Balance Sheet	June 30,		December 31,
Derivative instruments not designated as hedge⁽¹⁾:		Line Item	2011		2010

Derivative Assets:	Current
	Commodity contracts	Due from Managing General Partner-derivatives	$	375,197	$	345,618
	Non Current
	Commodity contracts	Due from Managing General Partner-derivatives		447,156		556,021

Total Derivative Assets			$	822,353	$	901,639

Derivative Liabilities:	Current
	Commodity contracts	Due to Managing General Partner-derivatives	$	49,398	$	84,806
	Basis protection contracts	Due to Managing General Partner-derivatives		254,003		212,336
	Non Current
	Basis protection contracts	Due to Managing General Partner-derivatives		321,548		420,505

Total Derivative Liabilities			$	624,949	$	717,647


(1)		As of June 30, 2011 and December 31, 2010, none of the Partnership’s derivative instruments were designated as hedges.

E-12

PDC 2002-D Limited Partnership

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)
June 30, 2011
(UNAUDITED)

The following tables presents the impact of the Partnership’s derivative instruments on the Partnership’s accompanying condensed statements of operations.


	Three Months Ended June 30,
	2011							2010
	Reclassification of							Reclassification of
	Realized Gains			Realized and				Realized Gains			Realized and
	(Losses) Included in			Unrealized Gains				(Losses) Included in			Unrealized Gains
	Prior Periods			for the Current				Prior Periods			for the Current
Statement of operations line item:	Unrealized			Period		Total		Unrealized			Period		Total

Commodity price risk management gain, net
Realized gains	$	9,354		$	1,420	$	10,774	$	18,549		$	7,246	$	25,795
Unrealized gains (losses)		(9,354	)		96,732		87,378		(18,549	)		148,618		130,069

Total commodity price risk management gain, net	$	—		$	98,152	$	98,152	$	—		$	155,864	$	155,864


	Six Months Ended June 30,
	2011								2010
	Reclassification of								Reclassification of
	Realized Gains			Realized and					Realized Gains			Realized and
	(Losses) Included in			Unrealized Gains					(Losses) Included in			Unrealized Gains
	Prior Periods			(Losses) for the					Prior Periods			for the Current
Statement of operations line item:	Unrealized			Current Period			Total		Unrealized			Period		Total

Commodity price risk management gain, net
Realized gains (losses)	$	36,341		$	(7,007	)	$	29,334	$	120,572		$	89,442	$	210,014
Unrealized gains (losses)		(36,341	)		49,753			13,412		(120,572	)		528,447		407,875

Total commodity price risk management gain, net	$	—		$	42,746		$	42,746	$	—		$	617,889	$	617,889

Concentration of Credit Risk. The Managing General Partner makes extensive use of over-the-counter derivative instruments that enable the Partnership to manage a portion of its exposure to price volatility from producing natural gas and crude oil. These arrangements expose the Partnership to the credit risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in the Managing General Partner’s credit facility agreement, as counterparties to its derivative contracts. To date, the Managing General Partner has had no counterparty default losses. The Managing General Partner has evaluated the credit risk of the Partnership’s derivative assets from counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on this evaluation, the Managing General Partner has determined that the impact of the nonperformance of the counterparties on the fair value of the Partnership’s derivative instruments was not significant.

Note 6 — Commitments and Contingencies

Legal Proceedings

Neither the Partnership nor PDC, in its capacity as the Managing General Partner of the Partnership, are party to any pending legal proceeding that PDC believes would have a materially adverse effect on the Partnership’s business, financial condition, results of operations or liquidity.

E-13

PDC 2002-D Limited Partnership

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS — (Continued)
June 30, 2011
(UNAUDITED)

Environmental

Due to the nature of the natural gas and crude oil industry, the Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures in place to avoid environmental contamination and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in the Partnership’s environmental risk profile. Liabilities are accrued when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. During the six months ended June 30, 2011, there were no new environmental remediation projects identified by the Managing General Partner for the Partnership. As of June 30, 2011 the Partnership has no accrued environmental liabilities. At December 31, 2010, the Partnership had accrued environmental remediation liabilities involving three Partnership wells in the amount of approximately $31,000, which is included in line item captioned “Accounts payable and accrued expenses” on the condensed Balance Sheets. The Managing General Partner is not currently aware of any environmental claims existing as of June 30, 2011, which have not been provided for or would otherwise have a material impact on the Partnership’s condensed financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on the Partnership’s properties.

E-14

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of the PDC 2002-D Limited Partnership,

In our opinion, the accompanying balance sheets and the related statements of operations, partners’ equity and cash flows present fairly, in all material respects, the financial position of PDC 2002-D Limited Partnership (the “Partnership”) at December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 9 to the financial statements, the Partnership has significant related party transactions with Petroleum Development Corporation and its subsidiaries.

/s/ PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

March 30, 2011

E-16

PDC 2002-D LIMITED PARTNERSHIP

Balance Sheets
As of December 31, 2010 and 2009


	2010			2009

ASSETS
Current assets:
Cash and cash equivalents	$	133,238		$	125,978
Accounts receivable		133,783			115,003
Crude oil inventory		40,211			34,652
Due from Managing General Partner-derivatives		345,618			234,618
Due from Managing General Partner-other, net		—			54,375

Total current assets		652,850			564,626

Natural gas and crude oil properties, successful efforts method, at cost		16,301,661			18,367,315
Less: Accumulated depreciation, depletion and amortization		(10,238,283	)		(10,553,171	)

Natural gas and crude oil properties, net		6,063,378			7,814,144

Due from Managing General Partner-derivatives		556,021			206,889
Other assets		86,464			67,711

Total noncurrent assets		6,705,863			8,088,744

Total Assets	$	7,358,713		$	8,653,370


LIABILITIES AND PARTNERS’ EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	40,662		$	13,878
Due to Managing General Partner-derivatives		297,142			200,841
Due to Managing General Partner-other, net		587,730			—

Total current liabilities		925,534			214,719

Due to Managing General Partner-derivatives		420,505			612,390
Asset retirement obligations		451,630			425,495

Total liabilities		1,797,669			1,252,604

Commitments and contingent liabilities
Partners’ equity:
Managing General Partner		1,306,336			1,597,595
Limited Partners — 1,455.26 units issued and outstanding		4,254,708			5,803,171

Total Partners’ equity		5,561,044			7,400,766

Total Liabilities and Partners’ Equity	$	7,358,713		$	8,653,370

See accompanying notes to financial statements.

E-17

PDC 2002-D LIMITED PARTNERSHIP

Statements of Operations
For the Years Ended December 31, 2010 and 2009


	2010			2009

Revenues:
Natural gas, NGLs and crude oil sales	$	1,387,024		$	1,281,672
Commodity price risk management gain (loss), net		861,349			(496,409	)

Total revenues		2,248,373			785,263

Operating costs and expenses:
Natural gas, NGLs and crude oil production cost		1,111,554			655,611
Direct costs — general and administrative		474,479			35,465
Depreciation, depletion and amortization		1,155,598			1,144,024
Loss on impairment of natural gas and crude oil properties		648,608			—
Accretion of asset retirement obligations		26,135			8,641

Total operating costs and expenses		3,416,374			1,843,741

Loss from operations		(1,168,001	)		(1,058,478	)
Interest expense		—			(6,989	)
Interest income		191			26,575

Net loss	$	(1,167,810	)	$	(1,038,892	)

Net loss allocated to partners	$	(1,167,810	)	$	(1,038,892	)
Less: Managing General Partner interest in net loss		(233,562	)		(207,778	)

Net loss allocated to Investor Partners	$	(934,248	)	$	(831,114	)

Net loss per Investor Partner unit	$	(642	)	$	(571	)

Investor Partner units outstanding		1,455.26			1,455.26

See accompanying notes to financial statements.

E-18

PDC 2002-D LIMITED PARTNERSHIP

Statements of Cash Flows
For the Years Ended December 31, 2010 and 2009


	2010			2009

Cash flows from operating activities:
Net loss	$	(1,167,810	)	$	(1,038,892	)
Adjustments to net loss to reconcile to net cash provided by operating activities:
Depreciation, depletion and amortization		1,155,598			1,144,024
Accretion of asset retirement obligations		26,135			8,641
Unrealized (gain) loss on derivative transactions		(555,716	)		1,491,115
Loss on impairment of natural gas and crude oil properties		648,608			—
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(18,780	)		3,632
(Increase) decrease in crude oil inventory		(5,559	)		19,592
Increase in other assets		(18,753	)		(18,494	)
Increase (decrease) in accounts payable and accrued expenses		26,784			(9,940	)
Decrease in due from Managing General Partner, Net		54,375			774,256
Increase in due to Managing General Partner, Net		587,730			—

Net cash provided by operating activities		732,612			2,373,934

Cash flows from investing activities:
Capital expenditures for natural gas and crude oil properties		(53,440	)		(43,764	)
Refund of capital expenditures for natural gas and crude oil properties		—			1,341

Net cash used in investing activities		(53,440	)		(42,423	)

Cash flows from financing activities:
Distributions to Partners		(671,912	)		(2,330,581	)

Net cash used in financing activities		(671,912	)		(2,330,581	)

Net increase in cash and cash equivalents		7,260			930
Cash and cash equivalents, beginning of year		125,978			125,048

Cash and cash equivalents, end of year	$	133,238		$	125,978

Supplemental cash flow information:
Cash payments for:
Interest	$	—		$	6,989

Supplemental disclosure of non-cash activity:
Asset retirement obligation, with corresponding increase to natural gas and crude oil properties	$	—		$	139,270

See accompanying notes to financial statements.

E-20

PDC 2002-D LIMITED PARTNERSHIP

Notes to Financial Statements


NOTE 1 —	GENERAL

As of December 31, 2010, there were 1,040 Investor Partners. PDC is the designated Managing General Partner of the Partnership and owns a 20% Managing General Partner ownership in the Partnership. According to the terms of the Limited Partnership Agreement, revenues, costs and cash distributions of the Partnership are allocated 80% to the limited partners (“Investor Partners”), which are shared pro rata, based upon the number of units in the Partnership, and 20% to the Managing General Partner. Through December 31, 2010, the Managing General Partner has repurchased 138.38 units of Partnership interests from Investor Partners at an average price of $5,501 per unit. As of December 31, 2010, the Managing General Partner owns 27.6% of the Partnership.

The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual investor partner. For more information about the Managing General Partner’s limited partner unit repurchase program, see Note 8, Partners’ Equity and Cash Distributions.


NOTE 2 —	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Management’s Estimates

The preparation of the Partnership’s financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S.”) requires the Partnership to make estimates and assumptions that affect the amounts reported in the Partnership’s financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to the financial statements include estimates of natural gas, natural gas liquids (“NGL”) and crude oil sales revenue, natural gas, NGLs and crude oil reserves, future cash flows from natural gas and crude oil properties and valuation of derivative instruments.

Basis of Presentation

The financial statements include only those assets, liabilities and results of operations of the partners which relate to the business of the Partnership.

Cash and Cash Equivalents. The Partnership considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Partnership maintains substantially all of its cash and cash equivalents in a bank account at one financial institution. The balance in the Partnership’s account is insured by Federal Deposit Insurance Corporation, or FDIC, up to $250,000 through December 31, 2013. The Partnership has not experienced losses in any such accounts to date and limits the Partnership’s exposure to credit loss by placing its cash and cash equivalents with high-quality financial institutions.

Accounts Receivable and Allowance for Doubtful Accounts. The Partnership’s accounts receivable are from purchasers of natural gas, NGLs and crude oil production. The Partnership sells substantially all of its natural gas, NGLs and crude oil to customers who purchase natural gas, NGLs and crude oil from other partnerships managed by the Partnership’s Managing General Partner. The Managing General Partner periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of its customers. No allowance was deemed necessary at December 31, 2010 or 2009.

E-21

PDC 2002-D LIMITED PARTNERSHIP

Notes to Financial Statements — (Continued)

Commitments. As Managing General Partner, PDC maintains performance bonds in the form of certificates of deposit for plugging, reclaiming and abandoning of the Partnership’s wells as required by governmental agencies. If a government agency were required to access these performance bonds to cover plugging, reclaiming or abandonment costs on a Partnership well, the Partnership would be obligated to fund any amounts in excess of funds previously withheld by the Managing General Partner to cover these expenses.

Inventory. Inventory consists of crude oil, stated at the lower of cost to produce or market.

Derivative Financial Instruments. The Partnership is exposed to the effect of market fluctuations in the prices of natural gas and crude oil. The Managing General Partner employs established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. The Managing General Partner’s policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes.

All derivative assets and liabilities are recorded on the balance sheets at fair value. PDC, as Managing General Partner, has elected not to designate any of the Partnership’s derivative instruments as hedges. Accordingly, changes in the fair value of the Partnership’s derivative instruments are recorded in the Partnership’s statements of operations and the Partnership’s net income is subject to greater volatility than if the Partnership’s derivative instruments qualified for hedge accounting. Changes in the fair value of derivative instruments related to the Partnership’s natural gas and crude oil sales are recorded in the line captioned, “Commodity price risk management gain (loss), net.” As positions designated to the Partnership settle, the realized gains and losses are netted for distribution. Net realized gains are paid to the Partnership and net realized losses are deducted from the Partnership’s cash distributions generated from production. The Partnership bears its designated share of counterparty risk.

Validation of a contract’s fair value is performed internally. While the Managing General Partner uses common industry practices to develop the Partnership’s valuation techniques, changes in the Partnership’s pricing methodologies or the underlying assumptions could result in significantly different fair values. See Note 3, Fair Value of Financial Instruments and Note 4, Derivative Financial Instruments, for a discussion of the Partnership’s derivative fair value measurements and a summary fair value table of open positions as of December 31, 2010 and 2009.

Natural Gas and Crude Oil Properties. Significant accounting polices related to the Partnership’s properties and equipment are discussed below.

The Partnership accounts for its natural gas and crude oil properties (the “Properties”) under the successful efforts method of accounting. Costs of proved developed producing properties and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. The Partnership calculates quarterly depreciation, depletion and amortization (“DD&A”) expense by using as the denominator the Partnership’s estimated quarter-end reserves adjusted to add back current period production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the statement of operations as a gain or loss. Upon the sale of individual wells, the proceeds are credited to accumulated DD&A. See Supplemental Natural Gas, NGL and Crude Oil Information — Unaudited, Net Proved Reserves for additional information regarding the Partnership’s reserve reporting. In accordance with the Agreement, all capital contributed to the Partnership after deducting syndication costs and a one-time management fee was used solely for the drilling of natural gas and crude oil wells. Accordingly, all such funds were advanced to the Managing General Partnership as of the last day of the year in which the Partnership was formed. The Partnership does not maintain an inventory of undrilled leases.

Proved Reserves. Partnership estimates of proved reserves are based on those quantities of natural gas, NGLs and crude oil which, by analysis of geoscience and engineering data, are estimated with reasonable certainty to be economically producible in the future from known reservoirs under existing conditions, operating methods and government regulations. Annually, the Managing General Partner engages independent petroleum engineers to

E-22

PDC 2002-D LIMITED PARTNERSHIP

Notes to Financial Statements — (Continued)

prepare a reserve and economic evaluation of the Partnership’s properties on a well-by-well basis as of December 31. Additionally, the Partnership adjusts reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating natural gas, NGLs and crude oil reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent the Partnership’s most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect the Partnership’s depreciation, depletion and amortization (“DD&A”) expense, a change in the Partnership’s estimated reserves could have an effect on the Partnership’s net income.

Proved Property Impairment. The Partnership assesses its producing natural gas and crude oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the Managing General Partner reasonably estimates the commodities to be sold. The estimates of future prices may differ from current market prices of natural gas, NGLs and crude oil. Certain events, including but not limited to, downward revisions in estimates to the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of the Partnership’s proved natural gas and crude oil properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis, which is predominantly unobservable data or inputs (Level 3), and is measured by the amount by which the net capitalized costs exceed their fair value. Estimated undiscounted future net cash flows are determined using prices from the forward price curve at the measurement date. Estimated discounted future net cash flows are determined utilizing a risk adjusted discount rate that is based on rates utilized by market participants that are commensurate with the risks inherent in the development of the underlying natural gas and oil reserves. Due to the availability of new reserve information, the Partnership reviewed its proved natural gas and crude oil properties for impairment at December 31, 2010 and 2009. See Note 10, Impairment of Capitalized Costs for additional disclosure related to the Partnership’s proved property impairment.

Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which the Partnership produces natural gas, NGLs and crude oil. The Partnership’s share of these taxes is expensed to the account “Natural gas, NGLs and crude oil production costs.” The Partnership’s production taxes payable are included in the caption “Accounts payable and accrued expenses” on the Partnership’s balance sheets.

Income Taxes. Since the taxable income or loss of the Partnership is reported in the separate tax returns of the individual investor partners, no provision has been made for income taxes by the Partnership.

Asset Retirement Obligations. The Partnership accounts for asset retirement obligations by recording the fair value of Partnership well plugging and abandonment obligations when incurred, which is at the time the well is spudded. Upon initial recognition of an asset retirement obligation, the Partnership increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in present value. The initial capitalized costs are depleted over the useful lives of the related assets, through charges to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling retirement obligations. See Note 6, Asset Retirement Obligations for a reconciliation of the changes in the Partnership’s asset retirement obligation from January 1, 2009, to December 31, 2010.

E-23

PDC 2002-D LIMITED PARTNERSHIP

Notes to Financial Statements — (Continued)

Revenue Recognition. Natural gas, NGLs and crude oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. The Partnership currently uses the “net-back” method of accounting for transportation arrangements of the Partnership’s natural gas sales. The Managing General Partner sells the Partnership’s natural gas at the wellhead and recognizes revenues based on the wellhead sales price since transportation costs downstream of the wellhead are incurred by the Partnership’s customers and reflected in the wellhead price. The majority of the Partnership’s natural gas, NGLs and crude oil is sold by the Managing General Partner under contracts with terms ranging from one month up to the life of the well. Virtually all of the Managing General Partner’s contract pricing provisions are tied to a market index with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions.

Certain reclassifications have been made to correct disclosures to conform to the June 30, 2011 presentation, specifically related to the fair value level classification of certain derivative instruments. The reclassification had no impact on the Partnership’s previously reported financial position, cash flows, net income or partners’ equity. See Note 4, Fair Value Measurements and Disclosures, for additional information regarding the fair value classification of the Partnership’s natural gas and crude oil derivative instruments.

Recent Accounting Standards.

The following standards have been recently adopted:

Fair Value Measurements and Disclosures. In January 2010, the Financial Accounting Standards Board (“FASB”) issued changes clarifying existing disclosure requirements related to fair value measurements. The update also added a new requirement to disclose fair value transfers in and out of Levels 1 and 2 and describe the reasons for the transfers. The adoption of these changes as of January 1, 2010, did not have a material impact on the Partnership’s accompanying financial statements.

The following standards have been recently issued:

Fair Value Measurements and Disclosures. In January 2010, the FASB issued changes clarifying existing disclosure requirements and requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements. The update also added a new requirement to disclose fair value transfers in and out of Levels 1 and 2 and describe the reasons for the transfers. These changes will be effective for the Partnership’s financial statements issued for the first interim or annual reporting period beginning after December 15, 2009, except for gross presentation of the Level 3 roll forward, which will become effective for annual reporting periods beginning after December 15, 2010. The Partnership’s adoption did not have a material effect on the Partnership’s financial statements and related disclosures.

Internal Control over Financial Reporting in Exchange Act Periodic Reports. By Final Rule effective September 21, 2010, the SEC amended its rules and forms to conform them to Section 404(c) of the Sarbanes-Oxley Act of 2002, or SOX, as added by the Dodd-Frank Wall Street Reform and Consumer Protection Act. The new SEC rules permanently exempt the Partnership, as a smaller reporting company filer, from the SOX requirement that registrants obtain and include in their annual report, filed with the SEC, their independent registered public accounting firm’s attestation report on the effectiveness of the registrant’s internal controls over financial reporting.

Subsequent Events. The Managing General Partner has evaluated the Partnership’s activities subsequent to December 31, 2010 through the issuance of the financial statements, and has concluded that no material subsequent events have occurred that would require additional recognition in the Partnership’s financial statements or disclosure in the notes to the Partnership’s financial statements.

E-24

PDC 2002-D LIMITED PARTNERSHIP

Notes to Financial Statements — (Continued)


NOTE 3 —	FAIR VALUE OF FINANCIAL INSTRUMENTS

Derivative Financial Instruments

Determination of Fair Value. The Partnership’s fair value measurements are estimated pursuant to a fair value hierarchy that requires the Partnership to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:


	•	Level 1 — Quoted prices (unadjusted) in active markets for identical assets or liabilities. Included in Level 1 are the Partnership’s commodity derivative instruments for New York Mercantile Exchange, or NYMEX, based natural gas swaps.

	•	Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means.

	•	Level 3 — Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Included in Level 3 are the Partnership’s commodity derivative instruments for Colorado Interstate Gas, or CIG, based natural gas swaps, crude oil swaps, natural gas and crude oil collars and the Partnership’s natural gas basis protection derivative instruments.

Derivative Financial Instruments. The Partnership measures the fair value of its derivative instruments based upon quoted market prices, where available. The valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. The methods described above may produce a fair value calculation that may not be indicative of future fair values. The Managing General’s valuation determination also gives consideration to nonperformance risk on Partnership liabilities in addition to nonperformance risk on PDC’s own business interests and liabilities, as well as the credit standing of derivative instrument counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in the Managing General Partner’s credit facility agreement, as counterparties to the Managing General Partner’s derivative contracts. The Managing General Partner has evaluated the credit risk of the counterparties holding the Partnership’s derivative assets using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on the Managing General Partner’s evaluation, the Managing General Partner has determined that the impact of the nonperformance of the counterparties on the fair value of the Partnership’s derivative instruments is insignificant. Validation of Partnership’s contracts’ fair value is performed internally and while the Managing General Partner uses common industry practices to develop its valuation techniques, changes in the Managing General Partner’s pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes these valuation methods are appropriate and consistent with those used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value. For more information

E-25

PDC 2002-D LIMITED PARTNERSHIP

Notes to Financial Statements — (Continued)

concerning the Partnership’s concentration of credit risk and the Managing General Partner’s evaluation of that risk, see Note 5, Concentration of Risk, below.

The following table presents, for each hierarchy level, the Partnership’s assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis as of December 31, 2010 and 2009.


	Level 2(c)			Level 3(d)			Total

As of December 31, 2009(a)
Assets:
Commodity based derivatives	$	368,767		$	72,740		$	441,507

Total assets		368,767			72,740			441,507

Liabilities:
Commodity based derivatives		(71,910	)		(383	)		(72,293	)
Basis protection derivative contracts		(740,938	)		—			(740,938	)

Total liabilities		(812,848	)		(383	)		(813,231	)

Net asset (liability)	$	(444,081	)	$	72,357		$	(371,724	)

As of December 31, 2010(b)
Assets:
Commodity based derivatives	$	867,993		$	33,646		$	901,639

Total assets		867,993			33,646			901,639

Liabilities:
Commodity based derivatives		(84,806	)		—			(84,806	)
Basis protection derivative contracts		(632,841	)		—			(632,841	)

Total liabilities		(717,647	)		—			(717,647	)

Net asset (liability)	$	150,346		$	33,646		$	183,992


(a)		The Partnership reclassified its NYMEX-based natural gas fixed-price swaps from Level 1 to Level 2 (decreasing the previously reported net asset in Level 1 by approximately $197,000) and CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability in Level 3 by approximately $641,000). The amounts presented reflect these reclassifications and conform to June 30, 2011 presentation.


(b)		The Partnership reclassified its NYMEX-based natural gas fixed-price swaps from Level 1 to Level 2 (decreasing the previously reported net asset in Level 1 by approximately $868,000) and CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability in Level 3 by approximately $718,000). The amounts presented reflect these reclassifications and conform to June 30, 2011 presentation.


(c)		Includes the Partnership’s fixed-price swaps and basis swaps.


(d)		Includes the Partnership’s natural gas collars.

E-26

PDC 2002-D LIMITED PARTNERSHIP

Notes to Financial Statements — (Continued)

The following table presents a reconciliation of the Partnership’s Level 3 fair value measurements.


	December 31,
	2010⁽¹⁾			2009⁽¹⁾

Fair value, net (liability) asset beginning of year	$	72,357		$	367,004
Changes in fair value included in statement of operations line item:
Commodity price risk management gain (loss), net		61,237			27,317
Settlements		(99,948	)		(321,964	)

Fair value, net liability end of year	$	33,646		$	72,357

Change in unrealized gain (loss) relating to assets (liabilities) still held as of December 31, 2010 and 2009, respectively, included in statement of operations line item:
Commodity price risk management loss, net	$	30,625		$	6,823


(1)		The Partnership reclassified its CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 decreasing the previously reported net liability at the beginning of 2010 by approximately $641,000 and decreasing the previously reported net asset at the beginning of 2009 by approximately $752,000. The amounts presented reflect these reclassifications and conform to June 30, 2011 presentation.

See Note 4, Derivative Financial Instruments, for additional disclosure related to the Partnership’s derivative financial instruments.

Non-Derivative Financial Assets and Liabilities.

The carrying values of the financial instruments comprising current assets and current liabilities approximate fair value due to the short-term maturities of these instruments.

See Note 2 — Summary of Significant Accounting Policies-Property and Equipment, Natural Gas and Crude Oil Properties and -Asset Retirement Obligations for a discussion of how the Partnership determined fair value for these obligations.


NOTE 4 —	DERIVATIVE FINANCIAL INSTRUMENTS

The Partnership’s results of operations and operating cash flows are affected by changes in market prices for natural gas and crude oil. To mitigate a portion of the Partnership’s exposure to adverse market changes, the Managing General Partner utilizes an economic hedging strategy for the Partnership’s natural gas and crude oil sales, in which PDC, as Managing General Partner, enters into derivative contracts on behalf of the Partnership to protect against price declines in future periods. While the Managing General Partner structures these derivatives to reduce the Partnership’s exposure to changes in price associated with the derivative commodity, they also limit the benefit the Partnership might otherwise have received from price increases in the physical market. The Managing General Partner believes the Partnership’s derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2010, the Partnership had derivative instruments in place for a portion of its anticipated production through 2013 for a total of 488,730 MMbtu of natural gas and 3,844 Bbls of crude oil. Partnership policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes.

The Managing General Partner uses natural gas and crude oil commodity derivative instruments to manage price risk for PDC as well as its sponsored drilling partnerships. The Managing General Partner sets these instruments for PDC and the various partnerships managed by PDC jointly by area of operations, whereby the allocation of derivative positions between PDC and each partnership is set at a fixed quantity. New positions have specific designations relative to the applicable partnership.

E-27

PDC 2002-D LIMITED PARTNERSHIP

Notes to Financial Statements — (Continued)

As of December 31, 2010, the Partnership’s derivative instruments were comprised of commodity collars and swaps and basis protection swaps.


	•	Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, PDC, as Managing General Partner receives the market price from the purchaser and receives the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty.

	•	Swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty.

	•	Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG basis protection swaps, which traditionally have negative differentials to NYMEX, PDC, as Managing General Partner, receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty.

E-28

PDC 2002-D LIMITED PARTNERSHIP

Notes to Financial Statements — (Continued)

The following table presents the location and fair value amounts of the Partnership’s derivative instruments on the accompanying balance sheets as of December 31, 2010 and 2009.


Derivative instruments not		December 31,
designated as hedge⁽¹⁾:	Balance Sheet Line Item	2010		2009

Derivative Assets:
Current
Commodity contracts	Due from Managing General Partner- derivatives	$	345,618	$	234,618
Non Current
Commodity contracts	Due from Managing General Partner- derivatives		556,021		206,889

Total Derivative Assets			901,639		441,507

Derivative Liabilities:
Current
Commodity contracts	Due to Managing General Partner- derivatives		84,806		14,362
Basis protection contracts	Due to Managing General Partner- derivatives		212,336		186,479
Non Current
Commodity contracts	Due to Managing General Partner- derivatives		—		57,931
Basis protection contracts	Due to Managing General Partner- derivatives		420,505		554,459

Total Derivative Liabilities			717,647		813,231

Net fair value of derivative instruments — asset (liability)		$	183,992	$	(371,724	)


(1)		As of December 31, 2010 and 2009, none of the Partnership’s derivative instruments were designated as hedges.

The following table presents the impact of the Partnership’s derivative instruments on the Partnership’s accompanying statements of operations.


	Year Ended December 31,
	2010							2009
	Reclassification of							Reclassification of
	Realized Gain			Realized and				Realized Gain			Realized and
	(Loss) Included in			Unrealized Gain				(Loss) Included in			Unrealized Gain
	Prior Periods			for the Current				Prior Periods			(Loss) for the
Statement of Operations Line Item	Unrealized			Period		Total		Unrealized			Current Period			Total

Commodity price risk management, net
Realized gain	$	33,777		$	271,856	$	305,633	$	858,148		$	136,558		$	994,706
Unrealized (loss) gain		(33,777	)		589,493		555,716		(858,148	)		(632,967	)		(1,491,115	)

Total commodity price risk management gain (loss), net	$	—		$	861,349	$	861,349	$	—		$	(496,409	)	$	(496,409	)

E-29

PDC 2002-D LIMITED PARTNERSHIP

Notes to Financial Statements — (Continued)


NOTE 5 —	CONCENTRATION OF RISK

Accounts Receivable. The Partnership’s accounts receivable are from purchasers of natural gas, NGLs and crude oil production. The Partnership sells substantially all of its natural gas, NGLs and crude oil to customers who purchase natural gas, NGLs and crude oil from other partnerships managed by the Partnership’s Managing General Partner. Inherent to the Partnership’s industry is the concentration of natural gas, NGL and crude oil sales to a few customers. This industry concentration has the potential to impact the Partnership’s overall exposure to credit risk, either positively or negatively, in that its customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions.

As of December 31, 2010 and 2009, the Partnership did not record an allowance for doubtful accounts. In making the estimate for receivables that are uncollectible, the Managing General Partner considers, among other things, historical write-offs and overall creditworthiness of the Partnership’s customers. It is reasonably possible that the Managing General Partner’s estimate of uncollectible receivables will change periodically. Historically, neither PDC nor any of the other partnerships managed by the Partnership’s Managing General Partner have experienced significant losses on accounts receivable. The Partnership did not incur any losses on accounts receivable for the years ended December 31, 2010 and 2009.

Major Customers. The following table presents the individual customers constituting 10% or more of total revenues.


	Year Ended December 31,
Major Customer	2010			2009

DCP Midstream LP (“DCP”)		25	%		27	%
Williams Production RMT (“Williams”),		33	%		31	%
Suncor Energy (USA) Inc. (“Suncor”)		41	%		40	%

Derivative Counterparties. A significant portion of the Partnership’s future liquidity is concentrated in derivative instruments that enable the Partnership to manage a portion of its exposure to price volatility from producing natural gas and crude oil. These arrangements expose the Partnership to the risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in the Managing General Partner’s credit facility agreement, as counterparties to its derivative contracts. To date, the Managing General Partner has had no counterparty default losses. The Managing General Partner has evaluated the credit risk of the Partnership’s derivative assets from counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. The Managing General Partner has determined based on this evaluation, that the impact of the nonperformance of the counterparties on the fair value of the Partnership’s derivative instruments is not significant.


NOTE 6 —	ASSET RETIREMENT OBLIGATIONS

The following table presents the changes in carrying amounts of the asset retirement obligations associated with the Partnership’s working interest in natural gas and crude oil properties.


	Year Ended December 31,
	2010		2009

Balance at beginning of year	$	425,495	$	277,584
Revisions in estimated cash flows		—		139,270
Accretion expense		26,135		8,641

Balance at end of year	$	451,630	$	425,495

E-30

PDC 2002-D LIMITED PARTNERSHIP

Notes to Financial Statements — (Continued)

If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost.


NOTE 7 —	COMMITMENTS AND CONTINGENCIES

Litigation. The Company is involved in various legal proceedings that it considers normal to its business. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. There are no assurances that settlements can be reached on acceptable terms or that adverse judgments, if any, in the remaining litigation will not be less than or exceed the amounts reserved.

Royalty Owner Class Action. On May 29, 2007, Glen Droegemueller, individually and as representative plaintiff on behalf of all others similarly situated, filed a class action complaint against the Managing General Partner in the District Court, Weld County, Colorado alleging that the Managing General Partner underpaid royalties on natural gas produced from wells operated by the Managing General Partner in parts of the State of Colorado (the “Droegemueller Action”). The plaintiff sought declaratory relief and to recover an unspecified amount of compensation for underpayment of royalties paid by the Managing General Partner pursuant to leases. The Managing General Partner moved the case to Federal Court on June 28, 2007. On October 10, 2008, the court preliminarily approved a settlement agreement between the plaintiffs and the Managing General Partner, on behalf of itself and the Partnership. Although the Partnership was not named as a party in the suit, the lawsuit states that this action relates to all wells operated by the Managing General Partner, which includes a majority of the Partnership’s wells in the Wattenberg field. For information regarding the number of Partnership wells located in this field, see Supplemental Natural Gas, NGL and Crude Oil Information — Unaudited, Costs Incurred in Natural Gas and Crude Oil Property Development Activities, which follows. The portion of the settlement relating to the Partnership’s wells for the year ended December 31, 2009 that has been expensed by the Partnership is approximately $13,000 including associated legal costs of approximately $5,000. The portion of the settlement relating to the Partnership’s wells for all periods through December 31, 2009 that has been expensed by the Partnership is approximately $232,000 including associated legal costs of approximately $20,000. This entire settlement of $212,084 was deposited by the Managing General Partner into an escrow account on November 3, 2008. Notice of the settlement was mailed to members of the class action suit in the fourth quarter of 2008. The final settlement was approved by the court on April 7, 2009. Settlement distribution checks were mailed in July 2009. During September 2009, the Partnership’s share of settlement costs were paid by the Partnership and related required judicial action from the settlement of the suit was implemented in this distribution.

The Partnership is involved in various other legal proceedings that are considered normal to the Partnership’s business. Although the results cannot be known with certainty, the Managing General Partner believes that the ultimate results of such proceedings will not have a material effect on the Partnership’s financial position, results of operations or liquidity.

Environmental. Due to the nature of the natural gas and crude oil industry, the Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures to avoid environmental contamination and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in the Partnership’s environmental risk profile. Liabilities are accrued when environmental assessments and/or clean-ups are probable and the costs can be reasonably estimated. During the year ended December 31, 2010, the Managing General Partner identified existing ground contamination and the Partnership incurred expenses of $0.5 million for ground contamination remediation. As of December 31, 2010, the Partnership accrued environmental remediation liabilities for three of the Partnership’s well pads involving seven wells in the amount of $31,000 included in line item captioned “Accounts payable and accrued expenses” on the Balance Sheet. The Managing General Partner is not aware of any environmental claims existing as of December 31, 2010, which have not been provided for or would otherwise have a material impact on the Partnership’s financial

E-31

PDC 2002-D LIMITED PARTNERSHIP

Notes to Financial Statements — (Continued)

statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on the Partnership’s properties.


NOTE 8 —	PARTNERS’ EQUITY AND CASH DISTRIBUTIONS

Partners’ Equity

Limited Partner Units. A Limited Partner unit represents the individual interest of an individual investor partner in the Partnership. No public market exists or will develop for the units. While units of the Partnership are transferable, assignability of the units is limited, requiring the consent of the Managing General Partner. Further, individual investor partners may request that the Managing General Partner repurchase units pursuant to the Unit Repurchase Program.

Allocation of Partners’ Interest. The table below presents the participation of the Investor Partners and the Managing General Partner in the revenues and costs of the Partnership.


				Managing
	Investor			General
	Partners			Partner

Partnership Revenue:
Natural gas, NGLs and crude oil sales		80	%		20	%
Preferred cash distribution(a)		100	%		0	%
Commodity price risk management gain (loss)		80	%		20	%
Sale of productive properties		80	%		20	%
Sale of equipment		0	%		100	%
Interest income		80	%		20	%
Partnership Operating Costs and Expenses:
Natural gas, NGLs and crude oil production and well operations costs(b)		80	%		20	%
Depreciation, depletion and amortization expense		80	%		20	%
Accretion of asset retirement obligations		80	%		20	%
Direct costs — general and administrative(c)		80	%		20	%


(a)		To the extent that Investor Partners receive preferred cash distributions, the allocations for Investor Partners will be increased accordingly and the allocation for the Managing General Partner will likewise be decreased. See Performance Standard Obligation of Managing General Partner below.

(b)		Represents operating costs incurred after the completion of productive wells, including monthly per-well charges paid to the Managing General Partner.

(c)		The Managing General Partner receives monthly reimbursement from the Partnership for direct costs — general and administrative incurred by the Managing General Partner on behalf of the Partnership.

Performance Standard Obligation of Managing General Partner. The Agreement provides for the enhancement of investor cash distributions if the Partnership does not meet a performance standard defined in the Agreement during the first 10 years of operations beginning 6 months after the funding of the Partnership. In general, if the average annual rate of return to the Investor Partners is less than 12.8% of their subscriptions, the allocation rate of cash distributions to Investor Partners will increase up to one-half of the Managing General Partner’s interest until the average annual rate increases to 12.8%, with a corresponding decrease to the Managing General Partner. The 12.8% rate of return is calculated by including the estimated benefit of a 25% income tax savings on the investment in the first year in addition to the cash distributions made to the Investor Partners as a percentage of the investment, divided by the number of years since the closing of the Partnership less six months.

E-32

PDC 2002-D LIMITED PARTNERSHIP

Notes to Financial Statements — (Continued)

Beginning in April 2009 when the conditions of the obligation arose and expiring upon the termination of Performance Standard Obligation provision in June 2013, the Partnership modified the allocation rate of all items of profit and loss and resulting cash available for distribution between the Managing General Partner and the Investor Partners, pursuant to this provision of the Agreement. For the twelve months ended December 31, 2010 and 2009, distributions paid to the Managing General Partner were reduced and distributions to the Investor Partners were increased by $76,686 and $115,058, respectively, as a result of the Preferred Cash Distribution made under the terms of this provision. Accumulated Preferred Cash Distributions paid to the Investor Partners through December 31, 2010 are $191,744.

Unit Repurchase Provisions. Investor Partners may request that the Managing General Partner repurchase units at any time beginning with the third anniversary of the first cash distribution of the Partnership. The repurchase price is set at a minimum of four times the most recent twelve months of cash distributions from production. In any calendar year, the Managing General Partner is conditionally obligated to purchase Investor Partner units aggregating to 10% of the initial subscriptions, if requested by an individual investor partner, subject to PDC’s financial ability to do so and upon receipt of opinions of counsel that the repurchase will not cause the Partnership to be treated as a “publicly traded partnership” or result in the termination of the Partnership for federal income tax purposes. Repurchase requests are fulfilled by the Managing General Partner on a first-come, first-serve basis.

Cash Distributions

The Agreement requires the Managing General Partner to distribute cash available for distribution no less frequently than quarterly. The Managing General Partner determines and distributes cash on a monthly basis, if funds are available for distribution. The Managing General Partner makes cash distributions of 80% to the Investor Partners and 20% to the Managing General Partner. Cash distributions began in July 2003. The following table presents the cash distributions made to the Investor Partners and Managing General Partner during the years indicated:


	Year Ended December 31,
	2010		2009

Cash distributions	$	671,912	$	2,330,581

Distributions to Partners in 2009 were impacted by non-recurring items. Receivables collected from the Managing General Partner for the over-withholding of production taxes related to Partnership production prior to 2007 including accrued interest thereon increased distributions by $0.9 million. Cash distribution in 2009 to the partners includes $0.3 million paid on the behalf of Investor Partners, to the Internal Revenue Service and state taxing authorities as a part of a comprehensive settlement agreement with taxing agencies. In addition, the Partnership’s payment to the Managing General Partner for royalty settlement costs of approximately $0.2 million decreased distributions in 2009. Both amounts had been previously accrued by the Partnership in “Due from (to) Managing General Partner — other, net.”


NOTE 9 —	TRANSACTIONS WITH MANAGING GENERAL PARTNER AND AFFILIATES

The Managing General Partner transacts business on behalf of the Partnership under the authority of the Drilling and Operating Agreement. Revenues and other cash inflows received on behalf of the Partnership are distributed to the Partners net of (after deducting) corresponding operating costs and other cash outflows incurred on behalf of the Partnership. The fair value of the Partnership’s portion of unexpired derivative instruments is recorded on the balance sheets under the captions “Due from Managing General Partner — derivatives” in the case of net unrealized gains or “Due to Managing General Partner — derivatives” in the case of net unrealized losses.

E-33

PDC 2002-D LIMITED PARTNERSHIP

Notes to Financial Statements — (Continued)

The following table presents transactions with the Managing General Partner reflected in the balance sheet line item — Due from Managing General Partner-other, net which remain undistributed or unsettled with the Partnership’s investors as of the dates indicated.


	December 31,
	2010			2009

Natural gas, NGLs and crude oil sales revenues collected from the Partnership’s third-party customers	$	83,892		$	175,272
Commodity Price Risk Management, Realized Gain		48,073			155,373
Other⁽¹⁾		(719,695	)		(276,270	)

Total Due (to) from Managing General Partner — other, net	$	(587,730	)	$	54,375


(1)		All other unsettled transactions, excluding derivative instruments, between the Partnership and the Managing General Partner. Except as noted below, the majority of these are operating costs or general and administrative costs which have not been deducted from distributions.

As of December 31, 2008, certain amounts recorded by the Partnership as assets in the account “Due from Managing General Partner — other, net” included amounts that were being held as restricted cash by the Managing General Partner, PDC, on behalf of the Partnership for the over-withholding of production taxes related to Partnership production prior to 2007, including accrued interest thereon. During September 2009, the Partnership collected these amounts totaling $1.0 million, from the Managing General Partner.

Additionally, certain amounts representing royalties on Partnership production paid in September 2009 were recorded by the Partnership as liabilities in the account “Due from Managing General Partner-other, net.” These amounts, which totaled approximately $232,000 including legal fees of approximately $20,000, represented the Partnership’s share of the court approved royalty litigation payment and settlement, more fully described in Note 7, Commitments and Contingencies. During September 2009, all settlement costs related to this litigation were paid by the Partnership, to the Managing General Partner.

For more information concerning the September 2009 settlement of the Partnership’s production tax refund receivable and Colorado royalty litigation settlement liability during September 2009, and its related impact to the Partnership’s cash distributions for the month of September 2009, see Note 8, Partners’ Equity and Cash Distributions.

Commencing with the 36^th month of well operations, the Managing General Partner started withholding from monthly Partnership distributable cash, amounts to be used to fund statutorily-mandated well plugging, abandonment and environmental site restoration expenditures. A Partnership well may be sold or plugged, reclaimed and abandoned, with consent of all non-operators, when depleted or an evaluation is made that the well has become uneconomical to produce. Per-well plugging fees withheld during 2010 and 2009 were $50 per well each month the well produced. The total amount withheld from Partnership distributable cash for the purposes of funding future Partnership obligations, is recorded on the balance sheets in the long-term asset line captioned, “Other Assets.”

The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note 4, Derivative Financial Instruments, with the Managing General Partner and its affiliates for years ended December 31, 2010 and 2009. “Well operations and maintenance” and “Gathering, compression and

E-34

PDC 2002-D LIMITED PARTNERSHIP

Notes to Financial Statements — (Continued)

processing fees” are included in the “Natural gas, NGLs and crude oil production costs” line item on the statements of operations.


	Year Ended December 31,
	2010		2009

Well operations and maintenance⁽¹⁾	$	996,079	$	547,923
Gathering, compression and processing fees⁽²⁾		46,992		44,787
Direct costs — general and administrative⁽³⁾		474,479		35,465
Cash distributions⁽⁴⁾⁽⁵⁾		115,301		531,402


(1)		Under the D&O Agreement, the Managing General Partner, as operator of the wells, receives payments for well charges and lease operating supplies and maintenance expenses from the Partnership when the wells begin producing.

		Well charges. The Managing General Partner receives reimbursement at actual cost for all direct expenses incurred on behalf of the Partnership, monthly well operating charges for operating and maintaining the wells during producing operations, which reflects a competitive field rate, and a monthly administration charge for Partnership activities.

		Under the D&O Agreement, PDC provides all necessary labor, vehicles, supervision, management, accounting, and overhead services for normal production operations, and may deduct from Partnership revenues a fixed monthly charge for these services. The charge for these operations and field supervision fees (referred to as “well tending fees”) for each producing well is based on competitive industry field rates which vary based on areas of operation. The well tending fees and administration fees may be adjusted annually to an amount equal to the rates initially established by the Drilling and Operating Agreement multiplied by the then current average of the Oil and Gas Extraction Index and the Professional and Technical Services Index, 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. This average is commonly referred to as the Accounting Procedure Wage Index Adjustment which is published annually by the Council of Petroleum Accountants Societies, or COPAS. These rates are reflective of similar costs incurred by comparable operators in the production field. PDC, in certain circumstances, has and may in the future, provided equipment or supplies, performed salt water disposal services and other services for the Partnership at the lesser of cost or competitive prices in the area of operations.

		The Managing General Partner as operator bills non-routine operations and administration costs to the Partnership at its cost. The Managing General Partner may not benefit by inter-positioning itself between the Partnership and the actual provider of operator services. In no event is any consideration received for operator services duplicative of any consideration or reimbursement received under the Agreement.

		The well operating, or well tending, charges cover all normal and regularly recurring operating expenses for the production, delivery and sale of natural gas, NGLs and crude oil, such as:

		• well tending, routine maintenance and adjustment;

		• reading meters, recording production, pumping, maintaining appropriate books and records; and

		• preparing production related reports to the Partnership and government agencies.

		The well supervision fees do not include costs and expenses related to:

		• the purchase or repairs of equipment, materials or third-party services;

		• the cost of compression and third-party gathering services, or gathering costs;

		• brine disposal; and

		• rebuilding of access roads.

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PDC 2002-D LIMITED PARTNERSHIP

Notes to Financial Statements — (Continued)


		These costs are charged at the invoice cost of the materials purchased or the third-party services performed.

		Lease Operating Supplies and Maintenance Expense. The Managing General Partner and its affiliates may enter into other transactions with the Partnership for services, supplies and equipment during the production phase of the Partnership, and is entitled to compensation at competitive prices and terms as determined by reference to charges of unaffiliated companies providing similar services, supplies and equipment. Management believes these transactions were on terms no less favorable than could have been obtained from non-affiliated third parties.

(2)		Under the Agreement, the Managing General Partner is responsible for gathering, compression, processing and transporting the natural gas produced by the Partnership to interstate pipeline systems, local distribution companies, and/or end-users in the area from the point the natural gas from the well is commingled with natural gas from other wells. In such a case, the Managing General Partner uses gathering systems already owned by PDC, or PDC constructs the necessary facilities if no such line exists. In such a case, the Partnership pays a gathering, compression and processing fee directly to the Managing General Partner at competitive rates. If a third-party gathering system is used, the Partnership pays the gathering fee charged by the third-party gathering the natural gas.

(3)		The Managing General Partner is reimbursed by the Partnership for all direct costs expended by them on the Partnership’s behalf for administrative and professional fees, such as legal expenses, audit fees and engineering fees for reserve reports.

(4)		Except as modified under the Standard Performance Obligation, the Agreement provides for the allocation of cash distributions 80% to the Investors Partners and 20% to the Managing General Partner. Cash distributions to the Managing General Partner for the twelve months ended December 31, 2010, and 2009 were reduced by $76,686 and $115,058, respectively, due to Preferred Cash Distribution made by the Managing General Partner to Investor Partners under the Performance Standard Obligation provision of the Agreement. The Investor Partner cash distributions during 2010 and 2009 include $57,604 and $180,345, respectively, for Investor Partner units repurchased by PDC. For additional disclosure regarding the allocation of cash distributions and provisions of the Standard Performance Obligation, refer to Note 8, Partners’ Equity and Cash Distributions.

(5)		Distributions to Partners in 2009 were impacted by non-recurring items. See Note 8, Partners’ Equity and Cash Distributions for detailed information on these transactions.


NOTE 10 —	IMPAIRMENT OF CAPITALIZED COSTS

The Partnership assesses its proved natural gas and crude oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the Managing General Partner reasonably estimates the commodities to be sold. The Partnership considers the receipt of the annual reserve report from independent engineers to be a triggering event. Therefore, impairment tests are completed as of December 31 each year. The estimates of future prices may differ from current market prices of natural gas and crude oil. Certain events, including but not limited to, downward revisions in estimates to the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of the Partnership’s proved natural gas and crude oil properties. If during the completion of the impairment test, net capitalized costs exceed undiscounted future net cash flows, as occurred for the year ended December 31, 2010, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis, which is predominantly unobservable data or inputs (Level 3), and is measured by the amount by which the net capitalized costs exceed their fair value. The Partnership’s estimated production used in the impairment testing is taken from the annual reserve report (See Supplemental Natural Gas, NGL and Crude Oil Information — Unaudited — Net Proved Reserves). Estimated undiscounted future net cash flows are determined using prices from the forward price curve at the measurement date. Estimated discounted future net cash flows were determined utilizing a risk adjusted discount rate that is based on rates utilized by market

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PDC 2002-D LIMITED PARTNERSHIP

Notes to Financial Statements — (Continued)

participants that are commensurate with the risks inherent in the development of the underlying natural gas and crude oil reserves. A decline in the forward price curves used to estimate future cash flows at December 31, 2010, accompanied by lower reserves reflected in the Partnership’s annual reserve report resulted in an impairment in the fourth quarter of 2010. This downward revision to the future net cash flows resulted primarily from a 917 or 66.8% decrease in future estimated MMcfs of natural gas production due to well economics and a reduction in prices from 2009. The Partnership recorded an impairment loss of $0.6 million for the year ended December 31, 2010. The impairment loss resulted from the downward revision to the fair value of discounted future net cash flows of production activities in the Grand Valley Field in Colorado. The Partnership recognized no impairment of its natural gas and crude oil properties for the year ended December 31, 2009. The Partnership has recognized impairment losses from inception to December 31, 2010 of $13.0 million on its natural gas and crude oil properties since the Partnership began operating in 2002.

E-37

PDC 2002-D LIMITED PARTNERSHIP

Supplemental Natural Gas, NGL and Crude Oil Information — Unaudited

Net Proved Reserves

The Partnership utilized the services of an independent petroleum engineer, Ryder Scott Company, L.P. (Ryder Scott), to estimate the Partnership’s 2010 and 2009 natural gas, NGLs and crude oil reserves. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC.

Proved reserves estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. The Partnership’s net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. Proved developed reserves are the quantities of natural gas, NGL and crude oil expected to be recovered from currently producing zones under the continuation of present operating methods. Proved undeveloped reserves, or PUDs, are those reserves expected to be recovered from existing wells where a relatively major expenditure is required for additional reserve development.

The Partnership’s estimated proved undeveloped reserves consist entirely of reserves attributable to the Wattenberg Field’s future initial Codell formation recompletion of the six productive J-Sand wells and future refracturings of 26 of the Partnership’s Codell formation wells. These additional Codell formation development activities, which are expected to start in 2012 as part of the Additional Codell Formation Development Plan, generally occur five to ten years after initial well drilling. Funding for this additional development work is expected to be provided by withholding distributions from investors. The Managing General Partner began to withhold funds from Partnership distributions in October 2010 for some of the Partnerships, in which they are the Managing General Partner. No funds have been withheld from this Partnership’s distributions as of December 31, 2010 and February 28,2011, respectively. Currently, the Partnership expects these additional development activities to be completed through approximately 2014. The time frame for development activity is impacted by individual well decline curves as well as the plan to maximize the financial impact of the additional development.

Reporting on NGLs in 2010

As a result of a computer system upgrade during the second half of 2009, the Managing General Partner was able to accumulate the Partnership’s NGLs sales revenues and production volumes for 2010. Prior to the system upgrade, the Partnership’s NGLs sales revenues and production volumes were included in the natural gas sales revenues and production volume statistical information. The NGLs are extracted by third-party purchasers from the Partnership’s natural gas production, after delivery. To provide additional information to the reader, the Partnership has revised the method of completing the year end reserve reports. The December 31, 2010 reserve report provides separately disclosed information relating to natural gas, NGLs and crude oil and condensate reserves.

The prices used to estimate the Partnership’s reserves, by commodity, are presented below.


	Price Used to Estimate Reserves
As of December 31,	Crude Oil		Natural Gas		NGLs
	(per Bbl)		(per Mcf)⁽¹⁾		(per Bbl)⁽¹⁾

2010⁽²⁾	$	71.42	$	3.30	$	34.10
2009⁽²⁾		55.14		3.82		—


(1)		Prior to 2010, NGLs were included in natural gas, which impacts the comparability for 2010 and 2009.

(2)		For 2010 and 2009, represents a 12-month average price calculated as the unweighted arithmetic average of the price on the first day of each month, January through December.

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PDC 2002-D LIMITED PARTNERSHIP

Supplemental Natural Gas, NGL and Crude Oil Information — Unaudited — (Continued)

The Partnership’s estimated 2010 and 2009 reserve volumes below were based on 12-month average prices. The following table presents the changes in estimated quantities of the Partnership’s reserves, all of which are located within the U. S.


							Crude Oil and			Natural Gas
	Natural Gas			NGLs			Condensate			Equivalent
	(MMcf)			(MBbl)			(MBbl)			(MMcfe)

Proved Reserves:
Proved reserves, January 1, 2009		5,296			—			369			7,510
Revisions of previous estimates		(1,871	)		—			(32	)		(2,063	)
Production		(236	)		—			(10	)		(296	)

Proved reserves, December 31, 2009		3,189			—			327			5,151
Revisions of previous estimates and reclassifications		(587	)		119			(11	)		61
Production		(186	)		(3	)		(8	)		(252	)

Proved reserves, December 31, 2010		2,416			116			308			4,960

Proved Developed Reserves, as of:
December 31, 2009		966			—			66			1,362

December 31, 2010		613			25			58			1,111

Proved Undeveloped Reserves, as of:
December 31, 2009		2,223			—			261			3,789

December 31, 2010		1,803			91			250			3,849

2010 Activity. At December 31, 2010, the Partnership’s estimated proved reserves experienced net downward revisions of previous estimates of 11 MBbls of crude oil and 587 MMcfs of natural gas. Additionally, the Partnership reclassified 119 MBbls of NGLs which were previously included and reported in 2009, with the Partnership’s proved natural gas reserves. These net revisions are the result in part, of revisions to proved developed producing reserves that includes a decrease of 167 MMcfs of natural gas accompanied by an increase of 28 MBbls of NGLs due to the reclassification, previously described. These revisions were primarily due to a decrease in performance projections in the Grand Valley Field’s wells, reduced economics resulting from lower twelve-month average natural gas prices partially offset by improved economics due to higher crude oil pricing, and the reclassification of NGLs reserves in the Wattenberg Field. Revisions to proved undeveloped reserves amounted to decreases of approximately 11 MBbls of crude oil and 420 MMcfs of natural gas along with the increase of 91 MBbls of NGLs. These revisions were primarily due to increased economics due to higher crude oil prices offset by reduced economics resulting from lower twelve-month average natural gas prices in addition to the Wattenberg Field NGLs reserve reclassification. There were no proved undeveloped reserves developed in 2010 and 2009.

2009 Activity. At December 31, 2009, the Partnership’s estimated proved natural gas and oil reserves experienced a net downward revision of previous estimates of 32 MBbls of crude oil and 1,871 MMcfs of natural gas. This net revision is the result of revisions to proved developed producing reserves that includes an increase of approximately 4 MBbls of crude oil and a decrease of 617 MMcfs of natural gas in addition to a downward revision of proved undeveloped reserves amounting to approximately 36 MBbls of crude oil and 1,254 MMcfs of natural gas. The downward revision to proved developed producing reserves was primarily due to a decrease in performance projections in the Grand Valley Field’s wells that was partially offset by an increase in performance projections in the Wattenberg Field’s wells. The change in field operational performance was accompanied by increased crude oil pricing. The downward revision to proved undeveloped natural gas and crude oil reserves was primarily due to

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PDC 2002-D LIMITED PARTNERSHIP

Supplemental Natural Gas, NGL and Crude Oil Information — Unaudited — (Continued)

reduced economics resulting from significantly lower twelve-month average natural gas prices, partially offset by higher crude oil prices.

Capitalized Costs and Costs Incurred in Natural Gas and Crude Oil Property Development Activities

Natural gas and crude oil development costs include costs incurred to gain access to and prepare development well locations for drilling; to drill and equip developmental wells; to complete additional production formations or recomplete existing production formations and to provide facilities to extract, treat, gather and store natural gas and crude oil.

The Partnership is engaged solely in natural gas and crude oil activities, all of which are located in the continental United States. Drilling operations began upon funding in December 2002 and all funds were advanced to the Managing General Partner as of December 31, 2002, for all planned drilling and completion activities. The Partnership owns an undivided working interest in 36 gross (32.3 net) productive natural gas and crude oil wells. The Partnership owns 27 wells located in the Wattenberg Field within the Denver-Julesburg (“DJ”) Basin, north and east of Denver, Colorado and nine wells located in the Grand Valley Field within the Piceance Basin, situated near the western border of Colorado.

Aggregate capitalized costs related to natural gas and crude oil development and production activities with applicable accumulated DD&A are presented below:


	As of December 31,
	2010			2009

Leasehold costs	$	457,715		$	516,200
Development costs		15,843,946			17,851,115

Natural gas and crude oil properties, successful efforts method, at cost		16,301,661			18,367,315
Less: Accumulated depreciation, depletion and amortization		(10,238,283	)		(10,553,171	)

Natural gas and crude oil properties, net	$	6,063,378		$	7,814,144

Included in “Development Costs” are the estimated costs associated with the Partnership’s asset retirement obligations discussed in Note 6, Asset Retirement Obligations.

The Partnership recorded impairment losses of $648,608 for the year ended December 31, 2010. Accordingly, the Partnership reduced “Natural gas and crude oil properties” by $2,119,094 and related “Accumulated depreciation, depletion and amortization” for those properties of $1,470,486 for the years ended December 31, 2010. See Note 10, Impairment of Capitalized Costs for additional disclosure related to the Partnership’s proved property impairment.

Since operations began in 2002, the Partnership recorded impairment losses of $12,966,532 through the year ended December 31, 2010. Accordingly, the Partnership reduced “Natural gas and crude oil properties” by $15,716,590 and related “Accumulated depreciation, depletion and amortization” for those properties of $2,750,058 through the year ended December 31, 2010.

The Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas and crude oil or environmental protection. These amounts totaled approximately $53,000 and $44,000 for 2010 and 2009, respectively.

E-40

FORM OF
LIMITED PARTNERSHIP AGREEMENT
OF PDC 2002-D LIMITED PARTNERSHIP,
A WEST VIRGINIA LIMITED PARTNERSHIP

This LIMITED PARTNERSHIP AGREEMENT (the “Agreement”) is made as of this 31st day of December, 2002, by and among Petroleum Development Corporation, a Nevada corporation, as managing general partner (the “Managing General Partner”), Steven R. Williams, a resident of West Virginia, as the Initial Limited Partner, and the Persons whose names are set forth on Exhibit A attached hereto, as additional general partners (the “Additional General Partners”) or as limited partners (the “Limited Partners” and, collectively with Additional General Partners, the “Investor Partners”), pursuant to the provisions of the West Virginia Uniform Limited Partnership Act (the “Act”), on the following terms and conditions:

ARTICLE I

The Partnership

1.01 Organization. Subject to the provisions of this Agreement, the parties hereto do hereby form a limited partnership (the “Partnership”) pursuant to the provisions of the Act. The Partners hereby agree to continue the Partnership as a limited partnership pursuant to the provisions of the Act and upon the terms and conditions set forth in this Agreement.

1.02 Partnership Name. The name of the Partnership shall be PDC 2002-D 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 ($1,750,000 with respect to PDC 2002-B and — C Limited Partnerships and PDC 2003-B and — C Limited Partnerships; and $3,500,000 with respect to 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

F-2

under the laws of West Virginia. The Managing General Partner shall cause amendments to the Certificate to be filed whenever required by the Act.

(b) The Managing General Partner shall execute and cause to be filed original or amended Certificates and shall take any and all other actions as may be reasonably necessary to perfect and maintain the status of the Partnership as a limited partnership or similar type of entity under the laws of any other states or jurisdictions in which the Partnership engages in business.

(c) The agent for service of process on the Partnership shall be Steven R. Williams or any successor as appointed by the Managing General Partner.

(d) Upon the dissolution of the Partnership, the Managing General Partner (or any successor managing general partner) shall promptly execute and cause to be filed certificates of dissolution in accordance with the Act and the laws of any other states or jurisdictions in which the Partnership has filed certificates.

1.07 Independent Activities. Each General Partner and each Limited Partner may, notwithstanding this Agreement, engage in whatever activities they choose, whether the same are competitive with the Partnership or otherwise, without having or incurring any obligation to offer any interest in such activities to the Partnership or any Partner. However, except as otherwise provided herein, the Managing General Partner and any of its Affiliates may pursue business opportunities that are consistent with the Partnership’s investment objectives for their own account only after they have determined that such opportunity either cannot be pursued by the Partnership because of insufficient funds or because it is not appropriate for the Partnership under the existing circumstances. Neither this Agreement nor any activity undertaken pursuant hereto shall prevent the Managing General Partner from engaging in such activities, or require the Managing General Partner to permit the Partnership or any Partner to participate in any such activities, and as a material part of the consideration for the execution of this Agreement by the Managing General Partner and the admission of each Investor Partner, each Investor Partner hereby waives, relinquishes, and renounces any such right or claim of participation. Notwithstanding the foregoing, the Managing General Partner still has an overriding fiduciary obligation to the Investor Partners.

1.08 Definitions. Capitalized words and phrases used in this Agreement shall have the following meanings:

(a) “Act” shall mean the Uniform Limited Partnership Act of the State of West Virginia, as set forth in 47-9-1 through 47-9-63 thereof, as amended from time to time (or any corresponding provisions of succeeding law).

(b) “Additional General Partner” shall mean an Investor Partner who purchases Units as an additional general partner, and such partner’s transferees and assigns. “Additional General Partners” shall mean all such Investor Partners. “Additional General Partner” shall not include, after a conversion, such Investor Partner who converts his interest into a Limited Partnership interest pursuant to Section 7.10 herein.

(c) “Administrative Costs” shall mean all customary and routine expenses incurred by the Managing General Partner for the conduct of program administration, including legal, finance, accounting, secretarial, travel, office rent, telephone, data processing and other items of a similar nature.

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

(e) “Agreement” or “Partnership Agreement” shall mean this Limited Partnership Agreement, as amended from time to time.

(f) “Capital Account” shall mean, with respect to any Partner, the capital account maintained for such Partner pursuant to Section 3.01 hereof.

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(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 101/2% 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

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any type, costs of plugging and abandoning any well participated in by the Partnership, and reimbursements and compensation to well operators, including charges paid to the Managing General Partner as unit operator during the drilling and completion phase of a well, plus the cost of the gathering system and of acquiring leasehold interests.

(o) “Dry Hole” shall mean any well abandoned without having produced oil or gas in commercial quantities.

(p) “Exploratory Well” shall mean a well drilled to find commercially productive hydrocarbons in an unproved area, to find a new commercially productive horizon in a field previously found to be productive of hydrocarbons at another horizon, or to significantly extend a known prospect.

(q) “Farmout” shall mean an agreement whereby the owner of the leasehold or working interest agrees to assign his interest in certain specific acreage to the assignees, retaining some interest such as an overriding royalty interest, an oil and gas payment, offset acreage or other type of interest, subject to the drilling of one or more specific wells or other performance as a condition of the assignment.

(r) “General Partners” shall mean the Additional General Partners and the Managing General Partner.

(s) “Gross Asset Value” shall mean, with respect to any asset, the asset’s adjusted basis for federal income tax purposes, except as follows:

(1) The initial Gross Asset Value of any asset contributed by a Partner to the Partnership shall be the gross fair market value of such asset, as determined by the contributing Partner and the Partnership;

(2) The Gross Asset Values of all Partnership assets shall be adjusted to equal their respective gross fair market values, as determined by the Managing General Partner, as of the following times: (a) the acquisition of an additional interest in the Partnership by any new or existing Partner in exchange for more than a de minimis Capital Contribution; (b) the distribution by the Partnership Property as consideration for an interest in the Partnership; and (c) the liquidation of the Partnership within the meaning of Treas. Reg. Section 1.704-1(b)(2)(ii)(g); provided, however, that the adjustments pursuant to clauses (a) and (b) above shall be made only if the Managing General Partner reasonably determines that such adjustments are necessary or appropriate to reflect the relative economic interests of the Partners in the Partnership;

(3) The Gross Asset Value of any Partnership asset distributed to any Partner shall be the gross fair market value of such asset on the date of distribution; and

(4) The Gross Asset Values of Partnership assets shall be increased (or decreased) to reflect any adjustments to the adjusted basis of such assets pursuant to Code Section 734(b) or Code Section 743(b), but only to the extent that such adjustments are taken into account in determining Capital Accounts pursuant to Treas. Reg. Section 1.704-1(b)(2)(iv)(m) and Section 3.02(g) hereof; provided, however, that Gross Asset Values shall not be adjusted pursuant to this Section (4) to the extent the Managing General Partner determines that an adjustment pursuant to Section (2) hereof is necessary or appropriate in connection with a transaction that would otherwise result in an adjustment pursuant to this Section (4).

If the Gross Asset Value of an asset has been determined or adjusted pursuant to Section (i), Section (ii), or (iv) hereof, such Gross Asset value shall thereafter be adjusted by the Depreciation taken into account with respect to such asset for purposes of computing Profits and Losses.

(t) “IDC” shall mean intangible drilling and development costs.

(u) “Independent Expert” shall mean a person with no material relationship with the Managing General Partner or its Affiliates who is qualified and who is in the business of rendering opinions regarding the value of oil and gas properties based upon the evaluation of all pertinent economic, financial, geologic and engineering information available to the Managing General Partner or its Affiliates.

(v) “Initial Limited Partner” shall mean Steven R. Williams or any successor to his interest.

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(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 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.

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(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 1.704-2(b)(2) and 1.704-2(d)(1).

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

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

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

(1) Any income of the Partnership that is exempt from federal income tax and not otherwise taken into account in computing Profits or Losses pursuant to this Section 1.08(rr) shall be added to such taxable income or loss;

(2) Any expenditures of the Partnership described in Code Section 705(a)(2)(B) or treated as Code Section 705(a)(2)(B) expenditures pursuant to Treas. Reg. Section 1.704-1(b)(2)(iv)(i), and not otherwise taken into account in computing Profits or Losses pursuant to this Section 1.08(rr) shall be subtracted from such taxable income or loss;

(3) In the event the Gross Asset Value of any Partnership asset is adjusted pursuant to Section 1.08(r)(2) or Section 1.08(r)(3) hereof, the amount of such adjustment shall be taken into account as gain or loss from the disposition of such asset for purposes of computing Profits or Losses;

(4) Gain or loss resulting from any disposition of Partnership Property with respect to which gain or loss is recognized for federal income tax purposes shall be computed by reference to the Gross Asset Value of the property disposed of, notwithstanding that the adjusted tax basis of such property differs from its Gross Asset Value;

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(5) In lieu of the depreciation, amortization, and other cost recovery deductions taken into account in computing such taxable income or loss, there shall be taken into account Depreciation for such fiscal year or other period, computed in accordance with Section 1.08(r) hereof; and

(6) Notwithstanding any other provisions of this Section 1.08(rr), any items which are specially allocated pursuant to this Agreement shall not be taken into account in computing Profits or Losses.

(tt) “Prospect” shall mean a contiguous oil and gas leasehold estate, or lesser interest therein, upon which drilling operations may be conducted. In general, a Prospect is an area in which the Partnership owns or intends to own one or more oil and gas interests, which is geographically defined on the basis of geological data by the Managing General Partner of such Partnership and which is reasonably anticipated by the Managing General Partner to contain at least one reservoir. An area covering lands which are believed by the Managing General Partner to contain subsurface structural or stratigraphic conditions making it susceptible to the accumulations of hydrocarbons in commercially productive quantities at one or more horizons. The area, which may be different for different horizons, shall be designated by the Managing General Partner in writing prior to the conduct of program operations and shall be enlarged or contracted from time to time on the basis of subsequently acquired information to define the anticipated limits of the associated hydrocarbon reserves and to include all acreage encompassed therein. A “prospect” with respect to a particular horizon may be limited to the minimum area permitted by state law or local practice, whichever is applicable, to protect against drainage from adjacent wells if the well to be drilled by the Partnership is to a horizon containing proved reserves.

(uu) “Prospectus” shall mean that Prospectus (including any preliminary prospectus), of which this Agreement is a part, pursuant to which the Units are being offered and sold.

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

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

(1) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(2) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(3) Estimates or proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas

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liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

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

(yy) “Reservoir” shall mean a separate structural or stratigraphic trap containing an accumulation of oil or gas.

(zz) “Roll-Up” shall mean a transaction involving the acquisition, merger, conversion, or consolidation, either directly or indirectly, of the Partnership and the issuance of securities of a roll-up entity. Such term does not include:

(1) a transaction involving securities of the Partnership that have been listed for at least 12 months on a national exchange or traded through the National Association of Securities Dealers Automated Quotation National Market System; or

(2) a transaction involving the conversion to corporate, trust or association form of only the Partnership if, as a consequence of the transaction, there will be no significant adverse change in any of the following:

(i) voting rights;

(ii) the term of existence of the Partnership;

(iii) sponsor compensation; or

(iv) the Partnership’s investment objectives.

(aaa) “Roll-Up Entity” shall mean a partnership, trust, corporation or other entity that would be created or survive after the successful completion of a proposed roll-up transaction.

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

(ccc) “Subscription” shall mean the amount indicated on the Subscription Agreement that an Investor Partner has agreed to pay to the Partnership as his Capital Contribution.

(ddd) “Subscription Agreement” shall mean the Agreement, attached to the Prospectus as Appendix B, pursuant to which an Investor subscribes to Units in the Partnership.

(eee) “Substituted Investor Partner” shall mean any Person admitted to the Partnership as an Investor Partner pursuant to Section 7.03(c) hereof.

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(fff) “Treas. Reg.” or “Regulation” shall mean the income tax regulations promulgated under the Code, as such regulations may be amended from time to time (including corresponding provisions of succeeding regulations).

(ggg) “Unit” shall mean an undivided interest of the Investor Partners in the aggregate interest in the capital and profits of the Partnership. Each Unit represents Capital Contributions of $20,000 to the Partnership.

(hhh) “Working Interest” shall mean an interest in an oil and gas leasehold which is subject to some portion of the costs of development, operation, or maintenance.

ARTICLE II

Capitalization

2.01 Capital Contributions of the Managing General Partner and Initial Limited Partner.

(a) (i) On or before the Offering Termination Date, the Managing General Partner shall make a Capital Contribution in cash to the Partnership of an amount equal to not less than 21^3/4% of the aggregate Capital Contributions of the Investor Partners.

(ii) The Managing General Partner shall pay all Lease and tangible drilling costs as well as all Intangible Drilling Costs in excess of such costs paid by the Investor Partners with respect to the Partnership; to the extent that such costs are greater than the Managing General Partner’s Capital Contribution set forth in the previous sentence, the Managing General Partner shall make such additional contributions in cash to the Partnership equal to such additional Costs; in the event of such additional Capital Contribution, the Managing General Partner’s share of profits and losses and distributions shall equal the percentage arrived at by dividing the Managing General Partner’s Capital Contribution by the Capital Available for Investment of the Partnership, except that such percentage may be revised by Sections 3.02 and 4.02.

(iii) In consideration of making its Capital Contribution as reflected in this Section 2.01(a), becoming a General Partner, subjecting its assets to the liabilities of the Partnership, and undertaking other obligations as herein set forth, the Managing General Partner shall receive the interest in the Partnership allocated in Article III hereof.

(b) The Initial Limited Partner shall contribute $100 in cash to the capital of the Partnership. Upon the earlier of the conversion of an Additional General Partner’s interest into a Limited Partner’s interest or the admission of a Limited Partner to the Partnership, the Partnership shall redeem in full, without interest or deduction, the Initial Limited Partner’s Capital Contribution, and the Initial Limited Partner shall cease to be a Partner.

2.02 Capital Contributions of the Investor Partners.

(a) Upon execution of this Agreement, each Investor Partner (whose names and addresses and number of Units to which Subscribed are set forth in Exhibit A) shall contribute to the capital of the Partnership the sum of $20,000 for each Unit purchased. The minimum subscription by an Investor Partner is one-quarter Unit ($5,000).

(b) The contributions of the Investor Partners pursuant to subsection 2.02(a) hereof shall be in cash or by check subject to collection.

(c) Until the Offering Termination Date and until such subsequent time as the contributions of the Investor Partners are invested in accordance with the provisions of the Prospectus, all monies received from persons subscribing as Investor Partners (i) shall continue to be the property of the investor making such payment, (ii) shall be held in escrow for such investor in the manner and to the extent provided in the Prospectus, and (iii) shall not be commingled with the personal monies or become an asset of the Managing General Partner or the Partnership.

(d) Upon the original sale of Units by the Partnership, subscribers shall be admitted as Partners no later than 15 days after the release from the escrow account of the Capital Contributions to the Partnership, in accordance with the terms of the Prospectus; subscriptions shall be accepted or rejected by the Partnership within 30 days of their receipt; if rejected, all subscription monies shall be returned to the subscriber forthwith.

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(e) Except as provided in Section 4.03 hereof, any proceeds of the offering of Units for sale pursuant to the Prospectus not used, committed for use, or reserved as operating capital in the Partnership’s operations within one year after the closing of such offering shall be distributed pro rata to the Investor Partners as a return of capital and the Managing General Partner shall reimburse such Investors for selling expenses, management fees, and offering expenses allocable to the return of capital.

(f) Until proceeds from the public offering are invested in the Partnership’s operations, such proceeds may be temporarily invested in income producing short-term, highly liquid investments, where there is appropriate safety of principal, such as U.S. Treasury Bills. Any such income shall be allocated pro rata to the Investor Partners providing such capital contributions.

2.03 Additional Contributions. Except as otherwise provided in this Agreement, no Investor Partner shall be required or obligated (a) to contribute any capital to the Partnership other than as provided in Section 2.02 hereof, or (b) to lend any funds to the Partnership. No interest shall be paid on any capital contributed to the Partnership pursuant to this Article II and, except as otherwise provided herein, no Partner, other than the Initial Limited Partner as authorized herein, may withdraw his Capital Contribution. The Units are nonassessable; however, General Partners are liable, in addition to their Capital Contributions, for Partnership obligations and liabilities represented by their ownership of interests as general partners, in accordance with West Virginia law.

ARTICLE III

Capital Accounts and Allocations

3.01 Capital Accounts.

(a) General. A separate Capital Account shall be established and maintained for each Partner on the books and records of the Partnership. Capital Accounts shall be maintained in accordance with Treas. Reg. Section 1.704-1(b) and any inconsistency between the provisions of this Section 3.01 and such regulation shall be resolved in favor of the regulation. In the event the Managing General Partner shall determine that it is prudent to modify the manner in which the Capital Accounts, or any debits or credits thereto (including, without limitation, debits or credits relating to liabilities that are secured by contributed or distributed property or that are assumed by the Partnership of the Partners), are computed in order to comply with such regulations, the Managing General Partner may make such modification, provided that it is not likely to have a material effect on the amounts distributable to any Partner pursuant to Section 9.03 hereof upon the dissolution of the Partnership. The Managing General Partner also shall (i) make any adjustments that are necessary or appropriate to maintain equality between the Capital Accounts of the Partners and the amount of Partnership capital reflected on the Partnership’s balance sheet, as computed for book purposes, in accordance with Treas. Reg. Section 1.704-1(b)(2)(iv)(q), and (ii) make any appropriate modifications in the event unanticipated events might otherwise cause this Agreement not to comply with Treas. Reg. Section 1.704-1(b).

(b) Increases to Capital Accounts. Each Partner’s Capital Account shall be credited with (i) the amount of money contributed by him to the Partnership; (ii) the amount of any Partnership liabilities that are assumed by him (within the meaning of Treas. Reg. Section 1.704-1(b)(2)(iv)(c)), but not by increases in his share of Partnership liabilities within the meaning of Code Section 752(a); (iii) the Gross Asset Value of property contributed by him to the Partnership (net of liabilities securing such contributed property that the Partnership is considered to assume or take subject to under Code Section 752); and (iv) allocations to him of Partnership Profits (or items thereof), including income and gain exempt from tax and Income and gain described in Treas. Reg. Section 1.704-1(b)(2)(iv)(g) (relating to adjustments to reflect book value).

(c) Decreases to Capital Accounts. Each Partner’s Capital Account shall be debited with (i) the amount of money distributed to him by the Partnership; (ii) the amount of his individual liabilities that are assumed by the Partnership (other than liabilities described in Treas. Reg. Section 1.704-1(b)(2)(iv)(b)(2) that are assumed by the Partnership and other than decreases in his share of Partnership liabilities within the meaning of Code Section 752(b)); (iii) the Gross Asset Value of property distributed to him by the Partnership (net of liabilities securing such distributed property that he is considered to assume or take subject to under Code Section 752); (iv) allocations to him of expenditures of the Partnership not deductible in computing Partnership taxable income and not properly

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chargeable to Capital Account (as described in Code Section 705(a)(2)(B)), and (v) allocations to him of Partnership Losses (or item thereof), including loss and deduction described in Treas. Reg. Section 1.704-1(b)(2)(iv)(g) (relating to adjustments to reflect book value), but excluding items described in (iv) above and excluding loss or deduction described in Treas. Reg. Section 1.704-1(b)(4)(iii) (relating to excess percentage depletion).

(d) Adjustments to Capital Accounts Related to Depletion.

(i) Solely for purposes of maintaining the Capital Accounts, each year the Partnership shall compute (in accordance with Treas. Reg. Section 1.704-1(b)(2)(iv)(k)) a simulated depletion allowance for each oil and gas property using that method, as between the cost depletion method and the percentage depletion method (without regard to the limitations of Code Section 613A(c)(3) which theoretically could apply to any Partner), which results in the greatest simulated depletion allowance. The simulated depletion allowance with respect to each oil and gas property shall reduce the Partners’ Capital Accounts in the same proportion as the Partners were allocated adjusted basis with respect to such oil and gas property under Section 3.03(a) hereof. In no event shall the Partnership’s aggregate simulated depletion allowance with respect to an oil and gas property exceed the Partnership’s adjusted basis in the oil and gas property (maintained solely for Capital Account purposes).

(ii) Upon the taxable disposition of an oil and gas property by the Partnership, the Partnership shall determine the simulated (hypothetical) gain or loss with respect to such oil and gas property (solely for Capital Account purposes) by subtracting the Partnership’s simulated adjusted basis for the oil and gas property (maintained solely for Capital Account purposes) from the amount realized by the Partnership upon such disposition. Simulated adjusted basis shall be determined by reducing the adjusted basis by the aggregate simulated depletion charged to the Capital Accounts of all Partners in accordance with Section 3.01(d)(i) hereof. The Capital Accounts of the Partners shall be adjusted upward by the amount of any simulated gain on such disposition in proportion to such Partners’ allocable share of the portion of total amount realized from the disposition of such property that exceeds the Partnership’s simulated adjusted basis in such property. The Capital Accounts of the Partners shall be adjusted downward by the amount of any simulated loss in proportion to such Partners’ allocable shares of the total amount realized from the disposition of such property that represents recovery of the Partnership’s simulated adjusted basis in such property.

(e) Restoration of Negative Capital Accounts. Except as otherwise provided in this Agreement, neither an Investor Partner nor the Initial Limited Partner shall be obligated to the Partnership or to any other Partner to restore any negative balance in his Capital Account. The Managing General Partner shall be obligated to restore the deficit balance in its Capital Account.

3.02 Allocation of Profits and Losses.

(a) General. Except as provided in this Section 3.02 or in Section 2.01(a) and Section 3.03 hereof, Profits and Losses during the production phase of the Partnership shall be allocated 80% to the Investor Partners and 20% to the Managing General Partner; provided, that if the Managing General Partner’s share of cash distributions is revised pursuant to Section 4.02, the allocations of Profits and Losses of the Partnership shall be allocated to reflect such revision. Notwithstanding the above allocations, the following special allocations shall be employed:

(i) irrespective of any revisions effected by Section 2.01(a) or Section 4.02, IDC and recapture of IDC shall be allocated 100% to the Investor Partners and 0% to the Managing General Partner, except as otherwise provided in the following clause; however, in the event that a portion of the Capital Contribution of the Managing General Partner is utilized for IDC, then IDC and recapture of IDC shall be allocated to the Investor Partners and the Managing General Partner in a percentage equal to their respective contribution to IDC;

(ii) irrespective of any revisions effected by Section 2.01(a) or Section 4.02, the following provisions shall apply: Organization and Offering Costs net of commissions, due diligence expenses and wholesaling fees payable to the dealer manager and the soliciting dealers shall be paid by the Managing General Partner; such commissions, due diligence expenses and wholesaling fees payable to the dealer manager and the soliciting dealers shall be allocated 100% to the Investor Partners and 0% to the Managing General Partner; except that Organization and Offering Costs in excess of 101/2% of Subscriptions shall be allocated 100% to the Managing General Partner and 0% to the Investor Partners;

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(iii) irrespective of any revisions effected by Section 2.01(a) or Section 4.02, the Management Fee shall be allocated 100% to the Investor Partners and 0% to the Managing General Partner;

(iv) irrespective of any revisions effected by Section 2.01(a) or Section 4.02, Costs of Leases and Costs of tangible equipment, including depreciation or cost recovery benefits, and revenues from the sale of equipment shall be allocated 0% to the Investor Partners and 100% to the Managing General Partner;

(v) Drilling and Completion Costs shall be allocated 80% to the Investor Partners and 20% to the Managing General Partner;

(vi) Direct Costs and Operating Costs shall be allocated 80% to the Investor Partners and 20% to the Managing General Partner; and

(vii) irrespective of any revisions effected by Section 2.01(a) or Section 4.02, Administrative Costs shall be borne 100% by and allocated 100% to the Managing General Partner.

(b) Capital Account Deficits. Notwithstanding anything to the contrary in Section 3.02(a), no Investor Partner shall be allocated any item to the extent that such allocation would create or increase a deficit in such Investor Partner’s Capital Account.

(i) Obligations to Restore. For purposes of this Section 3.02(b), in determining whether an allocation would create or increase a deficit in a Partner’s Capital Account, such Capital Account shall be reduced for those items described in Treas. Reg. Sections 1.704-1(b)(2)(ii)(d)(4), (5), and (6) and shall be increased by any amounts which such Partner is obligated to restore or is deemed obligated to restore pursuant to the penultimate sentences of Treas. Reg. Sections 1.704-2(g)(1) and 1.704-2(i)(5). Further, such Capital Accounts shall otherwise meet the requirements of Treas. Reg. Section 1.704-l(b)(2)(ii)(d).

(ii) Reallocations. Any loss or deduction of the Partnership, the allocation of which to any Partner is prohibited by this Section 3.02(b), shall be reallocated to those Partners not having a deficit in their Capital Accounts (as adjusted in Section 3.02(b)(i)) in the proportion that the positive balance of each such Partner’s adjusted Capital Account bears to the aggregate balance of all such Partners’ adjusted Capital Accounts, with any remaining losses or deductions being allocated to the Managing General Partner.

(iii) Qualified Income Offset. In the event any Investor Partner unexpectedly receives any adjustments, allocations, or distributions described in Treas. Reg. Section 1.704-1(b)(2)(ii)(d)(4), (5), or (6), items of Partnership income and gain shall be specifically allocated to such Partner in an amount and manner sufficient to eliminate (to the extent required by the Regulations) the total of the deficit balance in his Capital Account (as adjusted in Section 3.02(b)(i)) created by such adjustments, allocations, or distributions, provided that an allocation pursuant to this Section 3.02(b)(iii) shall be made if and only to the extent that such Partner would have a deficit in his Capital Account (as adjusted in Section 3.02(b)(i)) after all other allocations provided for in this Section 3 have been tentatively made as if this Section 3.02(b)(iii) were not in the Agreement.

(iv) Gross Income Allocations. In the event an Investor Partner has a deficit Capital Account at the end of any Partnership fiscal year which is in excess of the sum of (i) the amount such Partner is obligated to restore pursuant to any provision of this Agreement and (ii) the amount such Partner is deemed to be obligated to restore pursuant to the penultimate sentences of Treas. Reg. Sections 1.704-2(g)(1) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership income and gain in the amount of such excess as quickly as possible, provided that an allocation pursuant to this Section 3.02(b)(iv) shall be made only if and to the extent that such Partner would have a deficit Capital Account in excess of such sum after all other allocations provided for in this Section 3 have been made as if Section 3.02(b)(iii) hereof and this Section 3.02(b)(iv) were not in the Agreement.

(c) Minimum Gain Chargeback. Notwithstanding any other provision of this Section 3.02, if there is a net decrease in Partnership Minimum Gain during any taxable year, pursuant to Treas. Reg. Section 1.704-2(f)(1), all Partners shall be allocated items of partnership income and gain for that year equal to that partner’s share of the net decrease in Partnership Minimum Gain (within the meaning of Treas. Reg. Section 1.704-2(g)(2)). Notwithstanding the preceding sentence, no such chargeback shall be made to the extent one or more of the exceptions and/or waivers provided for in Treas. Reg. Section 1.704-2(f)(2)-(5) applies. Allocations pursuant to the previous sentence shall be

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made in proportion to the respective amounts required to be allocated to each Partner pursuant thereto. The items to be so allocated shall be determined in accordance with Treas. Reg. Section 1.704-2(f)(6). This Section 3.02(c) is intended to comply with the minimum gain chargeback requirement in such Section of the Regulations and shall be interpreted consistently therewith. To the extent permitted by such Section of the Regulations and for purposes of this Section 3.02(c) only, each Partner’s Capital Account (as adjusted in Section 3.02(b)(i)) shall be determined prior to any other allocations pursuant to this Section 3 with respect to such tax year and without regard to any net decrease in Partner Minimum Gain during such fiscal year.

(d) Partner Minimum Gain Chargeback. Notwithstanding any other provision of this Section 3 except Section 3.02(c), if there is a net decrease in Partner Minimum Gain attributable to a Partner Nonrecourse Debt during any Partnership fiscal year, rules similar to those contained in Section 3.02(c) shall apply in a manner consistent with Treas. Reg. Section 1.704-2(i)(4). This Section 3.02(d) is intended to comply with the minimum gain chargeback requirement in such Section of the Regulations and shall be interpreted consistently therewith. Solely for purposes of this Section 3.02(d), each Person’s Capital Account deficit (as so adjusted) shall be determined prior to any other allocations pursuant to this Section 3 with respect to such fiscal year, other than allocations pursuant to Section 3.02(c) hereof.

(e) Nonrecourse Deductions. Nonrecourse Deductions for any fiscal year or other period shall be specially allocated to the Partners (in proportion to their Units), in accordance with Treas. Reg. Section 1.704-2.

(f) Partner Nonrecourse Deductions. Any Partner Nonrecourse Deductions for any fiscal year or other period shall be specially allocated to the Partner who bears the economic risk of loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treas. Reg. Section 1.704-2(i).

(g) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Code Section 734(b) or Section 743(b) is required, pursuant to Treas. Reg. Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis) and such gain or loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Regulations.

(h) Curative Allocations.

(i) The “Regulatory Allocations” consist of the “Basic Regulatory Allocations,” as defined in Section 3.02(h)(ii) hereof, the “Nonrecourse Regulatory Allocations,” as defined in Section 3.02(h)(iii) hereof, and the “Partner Nonrecourse Regulatory Allocations,” as defined in Section 3.02(h)(iv) hereof.

(ii) The “Basic Regulatory Allocations” consist of allocations pursuant to Section 3.02(b)(ii), (iii), and (iv) hereof. Notwithstanding any other provision of this Agreement, other than the Regulatory Allocations, the Basic Regulatory Allocations shall be taken into account in allocating items of income, gain, loss, and deduction among the Partners so that, to the extent possible, the net amount of such allocations of other items and the Basic Regulatory Allocations to each Partner shall be equal to the net amount that would have been allocated to each such Partner if the Basic Regulatory Allocations had not occurred. For purposes of applying the foregoing sentence, allocations pursuant to this Section 3.02(h)(ii) shall only be made with respect to allocations pursuant to Section 3.02(g) hereof to the extent the Managing General Partner reasonably determines that such allocations will otherwise be inconsistent with the economic agreement among the parties to this Agreement.

(iii) The “Nonrecourse Regulatory Allocations” consist of all allocations pursuant to Section 3.02(c) and 3.02(e) hereof. Notwithstanding any other provision of this Agreement, other than the Regulatory Allocations, the Nonrecourse Regulatory Allocations shall be taken into account in allocating items of income, gain, loss, and deduction among the Partners so that, to the extent possible, the net amount of such allocations of other items and the Nonrecourse Regulatory Allocations to each Partner shall be equal to the net amount that would have been allocated to each Partner if the Nonrecourse Regulatory Allocations had not occurred. For purposes of applying the foregoing sentence (i) no allocations pursuant to this Section 3.02(h)(iii) shall be made prior to

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the Partnership fiscal year during which there is a net decrease in Partnership Minimum Gain, and then only to the extent necessary to avoid any potential economic distortions caused by such net decrease in Partnership Minimum Gain, and (ii) allocations pursuant to this Section 3.02(h)(iii) shall be deferred with respect to allocations pursuant to Section 3.02(e) hereof to the extent the Managing General Partner reasonably determines that such allocations are likely to be offset by subsequent allocations pursuant to Section 3.02(c).

(iv) The “Partner Nonrecourse Regulatory Allocations” consist of all allocations pursuant to Sections 3.02(d) and 3.02(f) hereof. Notwithstanding any other provision of this Agreement, other than the Regulatory Allocations, the Partner Nonrecourse Regulatory Allocations shall be taken into account in allocating items of income, gain, loss, and deduction among the Partners so that, to the extent possible, the net amount of such allocations of other items and the Partner Nonrecourse Regulatory Allocations to each Partner shall be equal to the net amount that would have been allocated to each such Partner if the Partner Nonrecourse Regulatory Allocations had not occurred. For purposes of applying the foregoing sentence (i) no allocations pursuant to this Section 3.02(h)(iv) shall be made with respect to allocations pursuant to Section 3.02(f) relating to a particular Partner Nonrecourse Debt prior to the Partnership fiscal year during which there is a net decrease in Partner Minimum Gain attributable to such Partner Nonrecourse Debt, and then only to the extent necessary to avoid any potential economic distortions caused by such net decrease in Partner Minimum Gain, and (ii) allocations pursuant to this Section 3.02(h)(iv) shall be deferred with respect to allocations pursuant to Section 3.02(f) hereof relating to a particular Partner Nonrecourse Debt to the extent the Managing General Partner reasonably determines that such allocations are likely to be offset by subsequent allocations pursuant to Section 3.02(d) hereof.

(v) The Managing General Partner shall have reasonable discretion with respect to each Partnership fiscal year, to apply the provisions of Sections 3.02(h)(ii), (iii), and (iv) hereof among the Partners in a manner that is likely to minimize such economic distortions.

(i) Other Allocations. Except as otherwise provided in this Agreement, all items of Partnership income, loss, deduction, and any other allocations not otherwise provided for shall be divided among the Unit Holders in the same proportions as they share Profits or Losses, as the case may be, for the year.

(j) Agreement to be Bound. The Partners are aware of the income tax consequences of the allocations made by this Section 3.02 and hereby agree to be bound by the provisions of this Section 3.02 in reporting their shares of Partnership income and loss for income tax purposes.

(k) Excess Nonrecourse Liabilities. Solely for purposes of determining a Partner’s proportionate share of the “excess nonrecourse liabilities” of the Partnership within the meaning of Treas. Reg. Section 1.752-3(a)(3), the Partners’ interests in Partnership profits are as follows: Investor Partners, 80% (in proportion to their Units) and the Managing General Partner, 20%.

(l) Allocation Variations. The Managing General Partner shall have the authority to vary allocations to preserve and protect the intention of the Partners as follows:

(i) It is the intention of the Partners that each Partner’s distributive share of income, gain, loss, deduction or credit (or any item thereof) shall be determined and allocated in accordance with this Article 3 to the fullest extent permitted by Code Section 704(b). In order to preserve and protect the allocations provided for in this Article 3, the Managing General Partner shall have the authority to allocate income, gain, loss, deduction or credit (or any item thereof) arising in any year differently than that expressly provided for in this Article 3, if and to the extent that determining and allocating income, gain, loss, deduction or credit (or any item thereof) in the manner expressly provided for in this Article 3 would cause the allocations of each Partner’s distributive share of income, gain, loss, deduction or credit (or any item thereof) not to be permitted by Code Section 704(b) and the Regulations promulgated thereunder. Any allocation made pursuant to this Section 3.02(l) shall be deemed to be a complete substitute for any allocation otherwise expressly provided for in this Article 3, and no amendment of this Agreement or further consent of any Partner shall be required therefor.

(ii) In making any such allocation (the “new allocation”) under this Section 3.02(l) the Managing General Partner shall be authorized to act only after having been advised by the Partnership’s accountants and/or counsel that, under Code Section 704(b) and the Regulations thereunder, (i) the new allocation is

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necessary, and (ii) the new allocation is the minimum modification of the allocations otherwise expressly provided for in this Article 3 which is necessary in order to assure that, either in the then current year or in any preceding year, each Partner’s distributive share of income, gain, loss, deduction or credit (or any item thereof) is determined and allocated in accordance with this Article 3 to the fullest extent permitted by Code Section 704(b) and the Regulations thereunder.

(iii) If the Managing General Partner is required by this Section 3.02(l) to make any new allocation in a manner less favorable to the Investor Partners than is otherwise expressly provided for in this Article 3, then the Managing General Partner shall have the authority, only after having been advised by the Partnership’s accountants and/or counsel that they are permitted by Code Section 704(b), to allocate income, gain, loss, deduction or credit (or any item thereof) arising in later years in such a manner as will make the allocations of income, gain, loss, deduction or credit (or any item thereof) to the Investor Partners as comparable as possible to the allocations otherwise expressly provided for or contemplated by this Article 3.

(iv) Any new allocation made by the Managing General Partner under this Section 3.02(l) in reliance upon the advice of the Partnership’s accountants and/or counsel shall be deemed to be made pursuant to the fiduciary obligation of the Managing General Partner to the Partnership and the Investor Partners, and no such new allocation shall give rise to any claim or cause of action by any Investor Partner.

(m) Tax Allocations: Code Section 704(c). In accordance with Code Section 704(c) and the Regulations thereunder, income, gain, loss, and deduction with respect to any property contributed to the capital of the Partnership shall, solely for tax purposes, be allocated among the Partners so as to take account of any variation between the adjusted basis of such property to the Partnership for federal income tax purposes and its initial Gross Asset Value (computed in accordance with Section 1.08(r)(1).

In the event the Gross Asset Value of any Partnership asset is adjusted pursuant to Section 1.08(r)(1) hereof, subsequent allocations of income, gain, loss, and deduction with respect to such asset shall take account of any variation between the adjusted basis of such asset for federal income tax purposes and its Gross Asset Value in the same manner as under Code Section 704(c) and the Regulations thereunder.

Any elections or other decisions relating to such allocations shall be made by the Managing General Partner in any manner that reasonably reflects the purpose and intention of this Agreement. Allocations pursuant to this Section 3.02(m) are solely for purposes of federal, state, and local taxes and shall not affect, or in any way be taken into account in computing, any Person’s Capital Account or share of Profits, Losses, other items, or distributions pursuant to any provision of this Agreement.

3.03 Depletion.

(a) The depletion deduction with respect to each oil and gas property of the Partnership shall be computed separately for each Partner in accordance with Code Section 613A(c)(7)(D) for Federal income tax purposes. For purposes of such computation, the adjusted basis of each oil and gas property shall be allocated in accordance with the Partners’ interests in the capital of the Partnership. Among the Investor Partners, such adjusted basis shall be apportioned among them in accordance with the number of Units held.

(b) Upon the taxable disposition of an oil or gas property by the Partnership, the amount realized from and the adjusted basis of such property shall be allocated among the Partners (for purposes of calculating their individual gain or loss on such disposition for Federal income tax purposes) as follows:

(i) The portion of the total amount realized upon the taxable disposition of such property that represents recovery of its simulated adjusted tax basis therein (as calculated pursuant to Section 3.01(d) hereof) shall be allocated to the Partners in the same proportion as the aggregate adjusted basis of such property was allocated to such Partners (or their predecessors in interest) pursuant to Section 3.03(a) hereof; and

(ii) The portion of the total amount realized upon the taxable disposition of such property that represents the excess over the simulated adjusted tax basis therein shall be allocated in accordance with the provisions of Section 3.02 hereof as if such gain constituted an item of Profit.

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3.04 Apportionment Among Partners.

(a) Except as otherwise provided in this Agreement, all allocations and distributions to the Investor Partners shall be apportioned among them pro rata based on Units held by the Partners.

(b) For purposes of Section 3.04(a) hereof, an Investor Partner’s pro rata share in Units shall be calculated as of the end of the taxable year for which such allocation has been made; provided, however, that if a transferee of a Unit is admitted as an Investor Partner during the course of the taxable year, the apportionment of allocations and distributions between the transferor and transferee of such Unit shall be made in the manner provided in Section 3.04(c) hereof.

(c) If, during any taxable year of the Partnership, there is a change in any Partner’s interest in the Partnership, each Partner’s allocation of any item of income, gain, loss, deduction, or credit of the Partnership for such taxable year, other than “allocable cash basis items” shall be determined by taking into account the varying interests of the Partners pursuant to such method as is permitted by Code Section 706(d) and the regulations thereunder. Each Partner’s share of “allocable cash basis items” shall be determined in accordance with Code Section 706(d)(2) by (i) assigning the appropriate portion of each item to each day in the period to which it is attributable, and (ii) allocating the portion assigned to any such day among the Partners in proportion to their interests in the Partnership at the close of such day. “Allocable cash basis item” shall have the meaning ascribed to it by Code Section 706(d)(2)(B) and the regulations thereunder.

ARTICLE IV

Distributions

4.01 Time of Distribution. Cash available for distribution shall be determined by the Managing General Partner. The Managing General Partner shall distribute, in its discretion, such cash deemed available for distribution, but such distributions shall be made not less frequently than quarterly.

4.02 Distributions.

(a) Except as otherwise provided below and in Section 2.01(a), all distributions (other than those made to wind up the Partnership in accordance with Section 9.03 hereof) shall be made 80% to the Investor Partners and 20% to the Managing General Partner. If the performance standard as defined below in subsection (b) is not fulfilled by a particular Partnership, that Partnership’s sharing arrangement shall be modified, as set forth herein, for up to a ten-year period commencing six months after the closing date of that Partnership and ending ten years following such closing date.

(b) The performance standard shall be as follows:

(i) If the Average Annual Rate of Return, as defined below, to the Investor Partners is less than 12.8% of their Subscriptions, the allocation rate of all items of profit and loss and cash available for distribution for Investor Partners shall be increased by ten percentage points above the then-current sharing arrangements for Investor Partners and the allocation rate with respect to such items for the Managing General Partner will be decreased by ten percentage points below the then-current sharing arrangements for the Managing General Partner, until the Average Annual Rate of Return shall have increased to 12.8% or more, or until ten years and six months shall have expired from the closing date of the Partnership, whichever event shall occur sooner.

(ii) Average Annual Rate of Return for purposes of this sharing arrangement shall be defined as (1) the sum of cash distributions and estimated initial tax savings of 25% of Subscriptions, realized for a $10,000 investment in the Partnership, divided by (2) $10,000 multiplied by the number of years (less six months) which have elapsed since the closing of the Partnership.

(c) The Partnership shall not require that Investor Partners reinvest their share of cash available for distribution in the Partnership. In no event shall funds be advanced or borrowed for purposes of distributions, if the amount of such distributions would exceed the Partnership’s accrued and received revenues for the previous four quarters, less paid and accrued operating costs with respect to such revenues. The determination of such revenues and costs shall be made in accordance with generally accepted accounting principles, consistently applied. Cash distributions from

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the Partnership to the Managing General Partner shall only be made in conjunction with distributions to Investor Partners and only out of funds properly allocated to the Managing General Partner’s account.

4.03 Capital Account Deficits. No distributions shall be made to any Investor Partner to the extent such distribution would create or increase a deficit in such Partner’s Capital Account (as adjusted in Section 3.02(b)(i)). Any distribution which is hereby prohibited shall be made to those Partners not having a deficit in their Capital Accounts (as adjusted in Section 3.02(b)(i)) in the proportion that the positive balance of each such Partner’s adjusted Capital Account bears to the aggregate balance of all such Partners’ adjusted Capital Accounts. Any cash available for distribution remaining after reduction of all adjusted Capital Accounts to zero shall be distributed to the Managing General Partner.

4.04 Liability Upon Receipt of Distributions.

(a) If a Partner has received a return of any part of his Capital Contribution without violation of the Partnership Agreement or the Act, he is liable to the Partnership for a period of one year thereafter for the amount of such returned contribution, but only to the extent necessary to discharge the Partnership’s liabilities to creditors who extended credit to the Partnership during the period the Capital Contribution was held by the Partnership.

(b) If a Partner has received a return of any part of his Capital Contribution in violation of either the Partnership Agreement or the Act, he is liable to the Partnership for a period of six years thereafter for the amount of the Capital Contribution wrongfully returned.

(c) A Partner receives a return of his Capital Contribution to the extent that the distribution to him reduces his share of the fair value of the net assets of the Partnership below the value, as set forth in the records required to be kept by West Virginia law, of his Capital Contribution which has not been distributed to him.

ARTICLE V

Activities

5.01 Management. The Managing General Partner shall conduct, direct, and exercise full and exclusive control over all activities of the Partnership. Investor Partners shall have no power over the conduct of the affairs of the Partnership or otherwise commit or bind the Partnership in any manner. The Managing General Partner shall manage the affairs of the Partnership in a prudent and businesslike fashion and shall use its best efforts to carry out the purposes and character of the business of the Partnership.

5.02 Conduct of Operations.

(a) (i) The Managing General Partner shall establish a program of operations for the Partnership which shall be in conformance with the following policies: (x) no less than 90% of the Capital Contributions net of Organization and Offering Costs and the Management Fee shall be applied to drilling and completing Development Wells; (y) the Partnership shall drill all of its wells in West Virginia, Ohio, Pennsylvania, Colorado, New York, Kentucky, Michigan, Indiana, Kansas, Montana, South Dakota, Tennessee, Utah, Wyoming, Nebraska, North Dakota, and/or Oklahoma and (z) the Prospects will be acquired pursuant to an arrangement whereby the Partnership will acquire up to 100% of the Working Interest, subject to landowners’ royalty interests and the royalty interests payable to unaffiliated third parties in varying amounts, provided that the weighted average of such royalty interests for all Prospects of the Partnership shall not exceed 20%.

(ii) The Investor Partners agree to participate in the Partnership’s program of operations as established by the Managing General Partner; provided, that no well drilled to the point of setting casing need be completed if, in the Managing General Partner’s opinion, such well is unlikely to be productive of oil or gas in quantities sufficient to justify the expenditures required for well completion. The Partnership may participate with others in the drilling of wells and it may enter into joint ventures, partnerships, or other such arrangements.

(b) All transactions between the Partnership and the Managing General Partner or its Affiliates shall be on terms no less favorable than those terms which could be obtained between the Partnership and independent third parties dealing at arm’s-length, subject to the provisions of Section 5.07 hereof.

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(c) The Partnership shall not participate in any joint operations on any co-owned Lease unless there has been acquired or reserved on behalf of the Partnership the right to take in kind or separately dispose of its proportionate share of the oil and gas produced from such Lease exclusive of production which may be used in development and production operations on the Lease and production unavoidably lost, and, if the Managing General Partner is the operator of such Lease, the Managing General Partner has entered into written agreements with every other person or entity owning any working or operating interest reserving to such person or entity a similar right to take in-kind, unless, in the opinion of counsel to the Partnership, the failure to reserve such right to take in-kind will not result in the Partnership being treated as a member of an association taxable as a corporation for Federal income tax purposes.

(d) The relationship of the Partnership and the Managing General Partner (or any Affiliate retaining or acquiring an interest) as co-owners in Leases, except to the extent superseded by an Operating Agreement consistent with the preceding paragraph and except to the extent inconsistent with this Partnership Agreement, shall be governed by the AAPL Form 610 Model Operating Agreement-1982, with a provision reserving the right to take production in-kind, naming the Managing General Partner as operator and the Partnership as a nonoperator, and with the accounting procedure to govern as the accounting procedures under such Operating Agreements.

(e) The Managing General Partner is generally expected to act as the operator of Partnership wells, and the Managing General Partner may designate such other persons as it deems appropriate to conduct the actual drilling and producing operations of the Partnership.

(f) As operator of Partnership wells, the Managing General Partner or its Affiliates shall receive per-well charges for each producing well based on the Working Interest acquired by the Partnership. These per-well charges shall be subject to annual adjustment beginning January 1, 2003 [with respect to Partnerships designated as “PDC 2001 — Limited Partnership,” January 1, 2004 with respect to Partnerships designated as “PDC 2002 — Limited Partnership” and January 1, 2005 with respect to Partnerships designated as “PDC 2003 — Limited Partnership”] as provided in the accounting procedures of the operating agreements.

(g) The Managing General Partner shall drill wells pursuant to drilling contracts with the Partnership based upon competitive prices and terms in the geographic area of operations, and to the extent that such prices exceed its Costs, the Managing General Partner shall be deemed to have received compensation.

(h) The Managing General Partner shall be reimbursed by the Partnership for Direct Costs. The Managing General Partner shall not be reimbursed for any Administrative Costs. All other expenses shall be borne by the Partnership.

(i) The Managing General Partner and its Affiliates may enter into other transactions (embodied in a written contract) with the Partnership, such as providing services, supplies, and equipment, and shall be entitled to compensation for such services at prices and on terms that are competitive in the geographic area of operations.

(j) The Partnership shall make no loans to the Managing General Partner or any Affiliate thereof.

(k) Neither the Managing General Partner nor any Affiliate shall loan any funds to the Partnership.

(l) The funds of the Partnership shall not be commingled with the funds of any other Person.

(m) Notwithstanding any provision herein to the contrary, no creditor shall receive, as a result of making any loan, a direct or indirect interest in the profits, capital, or property of the Partnership other than as a secured creditor.

(n) The Managing General Partner shall have a fiduciary responsibility for the safekeeping and use of all funds and assets of the Partnership, whether or not in the Managing General Partner’s possession or control, and shall not employ or permit another to employ such funds or assets in any manner except for the exclusive benefit of the Partnership.

5.03 Acquisition and Sale of Leases.

(a) To the extent the Partnership does not acquire a full interest in a Lease from the Managing General Partner, the remainder of the interest in such Lease may be held by the Managing General Partner which may either retain and exploit it for its own account or sell or otherwise dispose of all or a part of such remaining interest. Profits from

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such exploitation and/or disposition shall be for the benefit of the Managing General Partner to the exclusion of the Partnership. Any Leases acquired by the Partnership from the Managing General Partner shall be acquired only at the Managing General Partner’s Cost, unless the Managing General Partner shall have reason to believe that Cost is in excess of the fair market value of such property, in which case the price shall not exceed the fair market value. The Managing General Partner shall obtain an appraisal from a qualified independent expert with respect to sales of properties of the Managing General Partner and its Affiliates to the Partnership. Neither the Managing General Partner nor any Affiliate shall acquire or retain any carried, reversionary, or Overriding Royalty Interest on the Lease interests acquired by the Partnership, nor shall the Managing General Partner enter into any farmout arrangements with respect to its retained interest, except as provided in Section 5.05 hereof.

(b) The Partnership shall acquire only Leases reasonably expected to meet the stated purposes of the Partnership. No Leases shall be acquired for the purpose of a subsequent sale or farmout unless the acquisition is made after a well has been drilled to a depth sufficient to indicate that such an acquisition would be in the Partnership’s best interest.

(c) Neither the Managing General Partner nor its Affiliates, except other partnerships sponsored by them, shall purchase any productive properties from the Partnership.

5.04 Title to Leases.

(a) Record title to each Lease acquired by the Partnership may be temporarily held in the name of the Managing General Partner, or in the name of any nominee designated by the Managing General Partner, as agent for the Partnership until a productive well is completed on a Lease. Thereafter, record title to Leases shall be assigned to and placed in the name of the Partnership.

(b) The Managing General Partner shall take the necessary steps in its best judgment to render title to the Leases to be assigned to the Partnership acceptable for the purposes of the Partnership. No operation shall be commenced on any Prospect acquired by the Partnership unless the Managing General Partner is satisfied that the undertaking of such operation would be in the best interest of Investor Partners and the Partnership. The Managing General Partner shall be free, however, to use its own best judgment in waiving title requirements and shall not be liable to the Partnership or the Investor Partners for any mistakes of judgment unless such mistakes were made in a manner not in accordance with general industry standards in the geographic area and such mistakes were not the result of negligence by the Managing General Partner; nor shall the Managing General Partner or its Affiliates be deemed to be making any warranties or representations, express or implied, as to the validity or merchantability of the title to any Lease assigned to the Partnership or the extent of the interest covered thereby.

5.05 Farmouts.

(a) No Partnership Lease shall be farmed out, sold, or otherwise disposed of unless the Managing General Partner determines that (i) the Partnership lacks sufficient funds to drill on such Lease and is unable to obtain suitable financing, (ii) the Leases have been downgraded by events occurring after assignment to the Partnership, (iii) drilling on the Leases would result in an excessive concentration of Partnership funds creating, in the Managing General Partner’s opinion, undue risk to the Partnership, or (iv) the Managing General Partner, exercising the standard of a prudent operator, determines that the farmout is in the best interests of the Partnership.

(b) Farmouts between the Partnership and the Managing General Partner or its Affiliates, including any other affiliated limited partnership, shall be effected on terms deemed fair by the Managing General Partner. The Managing General Partner, exercising the standard of a prudent operator, shall determine that the farmout is in the best interest of the Partnership and the terms of the farmout are consistent with and, in any case, no less favorable to the Partnership than those utilized in the geographic area of operations for similar arrangements. The respective obligations and revenue sharing of all affiliated parties to the transactions shall be substantially the same, and the compensation arrangement or any other interest or right of either the Managing General Partner or its Affiliates shall be substantially the same in each participating partnership or, if different, shall be reduced to reflect the lower compensation arrangement.

5.06 Release, Abandonment, and Sale or Exchange of Properties. Except as provided elsewhere in this Article V and in Section 6.03, the Managing General Partner shall have full power to dispose of the production and

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other assets of the Partnership, including the power to determine which Leases shall be released or permitted to terminate, those wells to be abandoned, whether any Lease or well shall be sold or exchanged, and the terms therefor. In the event the Managing General Partner sells, transfers, or otherwise disposes of nonproducing property of the Partnership, the sale, transfer, or disposition shall, to the extent possible, be made at a price which is the higher of the fair market value of the property on the date of the sale, transfer, or disposition or the Cost of such property to the Partnership.

5.07 Certain Transactions.

(a) Whenever the Managing General Partner or its Affiliates sell, transfer, or assign an interest in a Prospect to the Partnership, they shall assign to the Partnership an equal proportionate interest in each of the Leases comprising the Prospect. If the Managing General Partner or its Affiliates (except another affiliated partnership in which the interest of the Managing General Partner or its Affiliates is identical to or less than their interest in the Partnership) subsequently propose to acquire an interest in a Prospect in which the Partnership possesses an interest or in a Prospect abandoned by the Partnership within one year preceding such proposed acquisition, the Managing General Partner or its Affiliates shall offer an equivalent interest therein to the Partnership; and, if funds, including borrowings, are not available to the Partnership to enable it to consummate a purchase of an equivalent interest in such property and pay the development costs thereof, neither the Managing General Partner nor any of its Affiliates shall acquire such interest or property. The term “abandoned” shall mean the termination, either voluntarily or by operation of the Lease or otherwise, of all of the Partnership’s interest in the Prospect. These limitations shall not apply after the lapse of five years from the date of formation of the Partnership.

(b) The geological limits of a Prospect shall be enlarged or contracted on the basis of subsequently acquired geological data that further defines the productive limits of the underlying oil and/or gas reservoir and shall include all of the acreage determined by such subsequent data to be encompassed by such reservoir; further, where the Managing General Partner or Affiliate owns a separate property interest in such enlarged area, such interest shall be sold to the Partnership if the activities of the Partnership were material in establishing the existence of proved undeveloped reserves which are attributable to such separate property interest; provided, however, that the Partnership shall not be required to expend additional funds unless they are available from the initial capitalization of the Partnership or if the Managing General Partner believes it is prudent to borrow for the purpose of acquiring such additional acreage.

(c) The Partnership shall not purchase properties from or sell properties to any other affiliated partnership. This prohibition, however, shall not apply to transactions among affiliated partnerships by which property is transferred from one to another in exchange for the transferee’s obligation to conduct drilling activities on such property or to joint ventures among such affiliated partnerships, provided that the respective obligations and revenue sharing of all parties to the transaction are substantially the same and the compensation arrangement or any other interest or right of either the Managing General Partner or its Affiliates is the same in each affiliated partnership, or, if different, the aggregate compensation of the Managing General Partner is reduced to reflect the lower compensation arrangement.

(d) During the existence of the Partnership, and before it has ceased operations, neither the Managing General Partner nor any of its Affiliates (excluding another partnership where the Managing General Partner’s or its Affiliates’ interest in such partnership is identical to or less than their interest in the Partnership) shall acquire, retain, or drill for their own account any oil and gas interest in any Prospect in which the Partnership possesses an interest, except for transactions whereby the Managing General Partner or such Affiliate acquires or retains a proportionate Working Interest, the respective obligations of the Managing General Partner or the Affiliate and the Partnership are substantially the same after the sale of the interest to the Partnership, and the Managing General Partner’s or Affiliate’s interest in revenues does not exceed the amount proportionate to its Working Interest.

(e) Any services, equipment, or supplies which the Managing General Partner or an Affiliate furnishes to the Partnership shall be furnished at the lesser of the Managing General Partner’s or the Affiliate’s Cost or a competitive rate which could be obtained in the geographical area of operations unless the Managing General Partner or any Affiliate is engaged to a substantial extent, as an ordinary and ongoing business, in providing such services, equipment, or supplies to others in the industry, in which event, the services, supplies, or equipment may be provided by such person to the Partnership at prices competitive with those charged by others in the geographical

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area of operations which would be available to the Partnership. If such entity is not engaged in the business as set forth above, then such compensation, price or rental shall be the cost of such services, equipment or supplies to such entity, or the competitive rate which could be obtained in the area, whichever is less. Any drilling services provided by the Managing General Partner or its Affiliates shall be billed only on a per foot, per day, or per hour rate, or some combination thereof. No turnkey drilling contracts shall be made between the Managing General Partner or its Affiliates and the Partnership. Neither the Managing General Partner nor its Affiliates shall profit by drilling in contravention of its fiduciary obligations to the Partnership. Any such services for which the Managing General Partner or an Affiliate is to receive compensation shall be embodied in a written contract which precisely describes the services to be rendered and all compensation to be paid.

(f) Advance payments by the Partnership to the Managing General Partner are prohibited, except where necessary to secure tax benefits of prepaid drilling costs. These payments, if any, shall not include nonrefundable payments for completion costs prior to the time that a decision is made that the well or wells warrant a completion attempt.

(g) Neither the Managing General Partner nor its Affiliates shall make any future commitments of the Partnership’s production which do not primarily benefit the Partnership, nor shall the Managing General Partner or any Affiliate utilize Partnership funds as compensating balances for the benefit of the Managing General Partner or the Affiliate.

(h) No rebates or give-ups may be received by the Managing General Partner or any of its Affiliates, nor may the Managing General Partner or any Affiliate participate in any reciprocal business arrangements which would circumvent these restrictions.

(i) During a period of five years from the date of formation of the Partnership, if the Managing General Partner or any of its Affiliates proposes to acquire from an unaffiliated person an interest in a Prospect in which the Partnership possesses an interest or in a Prospect in which the Partnership’s interest has been terminated without compensation within one year preceding such proposed acquisition, the following conditions shall apply:

(1) If the Managing General Partner or the Affiliate does not currently own property in the Prospect separately from the Partnership, then neither the Managing General Partner nor the Affiliate shall be permitted to purchase an interest in the Prospect.

(2) If the Managing General Partner or the Affiliate currently owns a proportionate interest in the Prospect separately from the Partnership, then the interest to be acquired shall be divided between the Partnership and the Managing General Partner or the Affiliate in the same proportion as is the other property in the Prospect; provided however, if cash or financing is not available to the Partnership to enable it to consummate a purchase of the additional interest to which it is entitled, then neither the Managing General Partner nor the Affiliate shall be permitted to purchase any additional interest in the Prospect.

(j) If the Partnership acquires property pursuant to a farmout or joint venture from an affiliated program, the Managing General Partner’s and/or its Affiliates’ aggregate compensation associated with the property and any direct and indirect ownership interest in the property may not exceed the lower of the compensation and ownership interest the Managing General Partner and/or its Affiliates could receive if the property were separately owned or retained by either one of the programs.

(k) Neither the Managing General Partner nor any Affiliate, including affiliated programs, may purchase or acquire any property from the Partnership, directly or indirectly, except pursuant to transactions that are fair and reasonable to the Investor Partners of the Partnership and then subject to the following conditions:

(1) A sale, transfer or conveyance, including a farmout, of an undeveloped property from the Partnership to the Managing General Partner or an Affiliate, other than an affiliated program, must be made at the higher of cost or fair market value.

(2) A sale, transfer or conveyance of a developed property from the Partnership to the Managing General Partner or an Affiliate, other than an affiliated program in which the interest of the Managing General Partner is substantially similar to or less than its interest in the subject Partnership, shall not be permitted except in connection with the liquidation of the Partnership and then only at fair market value.

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(3) Except in connection with farmouts or joint ventures made in compliance with Section 5.07(j) above, a transfer of an undeveloped property from the Partnership to an affiliated drilling program must be made at fair market value if the property has been held for more than two years. Otherwise, if the Managing General Partner deems it to be in the best interest of the Partnership, the transfer may be made at cost.

(4) Except in connection with farmouts or joint ventures made in compliance with Section 5.07(j) above, a transfer of any type of property from the Partnership to an affiliated production purchase or income program must be made at fair market value if the property has been held for more than six months or there have been significant expenditures made in connection with the property. Otherwise, if the Managing General Partner deems it to be in the best interest of the Partnership, the transfer may be made at cost as adjusted for intervening operations.

(l) If the Partnership participates in other partnerships or joint ventures (multi-tier arrangements), the terms of any such arrangements shall not result in the circumvention of any of the requirements or prohibitions contained in this Partnership Agreement, including the following:

(1) there will be no duplication or increase in organization and offering expenses, the Managing General Partner’s compensation, Partnership expenses or other fees and costs;

(2) there will be no substantive alteration in the fiduciary and contractual relationship between the Managing General Partner and the Investor Partners; and

(3) there will be no diminishment in the voting rights of the Investor Partners.

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

(1) An appraisal of all Partnership assets shall be obtained from a competent independent expert. If the appraisal will be included in a prospectus used to offer the securities of a Roll-Up Entity, the appraisal shall be filed with the Securities and Exchange Commission and the Administrator as an exhibit to the registration statement for the offering. The appraisal shall be based on all relevant information, including current reserve estimates prepared by an independent petroleum consultant, and shall indicate the value of the Partnership’s assets assuming an orderly liquidation as of a date immediately prior to the announcement of the proposed Roll-Up transaction. The appraisal shall assume an orderly liquidation of Partnership assets over a 12-month period. The terms of the engagement of the independent expert shall clearly state that the engagement is for the benefit of the Partnership and the Investor Partners. A summary of the independent appraisal, indicating all material assumptions underlying the appraisal, shall be included in a report to the Investor Partners in connection with a proposed Roll-Up.

(2) In connection with a proposed Roll-Up, Investor Partners who vote “no” on the proposal shall be offered the choice of:

(i) accepting the securities of the Roll-Up Entity offered in the proposed Roll-Up; or

(ii) (a) remaining as Investor Partners in the Partnership and preserving their interests therein on the same terms and conditions as existed previously; or (b) receiving cash in an amount equal to the Investor Partners’ pro-rata share of the appraised value of the net assets of the Partnership.

(3) The Partnership shall not participate in any proposed Roll-Up which, if approved, would result in the diminishment of any Investor Partner’s voting rights under the Roll-Up Entity’s chartering agreement. In no event shall the democracy rights of Investor Partners in the Roll-Up Entity be less than those provided for under Sections 7.07 and 7.08 of this Agreement. If the Roll-Up Entity is a corporation, the democracy rights of Investor Partners shall correspond to the democracy rights provided for in this Agreement to the greatest extent possible.

(4) The Partnership shall not participate in any proposed Roll-Up transaction which includes provisions which would operate to materially impede or frustrate the accumulation of shares by any purchaser of the securities of the Roll-Up Entity (except to the minimum extent necessary to preserve the tax status of the Roll-Up Entity); nor shall the Partnership participate in any proposed Roll-Up transaction which would limit

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the ability of an Investor Partner to exercise the voting rights of its securities of the Roll-Up Entity on the basis of the number of Partnership Units held by that Investor Partner.

(5) The Partnership shall not participate in a Roll-Up in which Investor Partners’ rights of access to the records of the Roll-Up Entity will be less than those provided for under Section 8.01 of this Agreement.

(6) The Partnership shall not participate in any proposed Roll-Up transaction in which any of the costs of the transaction would be borne by the Partnership if the Roll-Up is not approved by the Investor Partners.

(7) The Partnership shall not participate in a Roll-Up transaction unless the Roll-Up transaction is approved by at least 662/3% in interest of the Investor Partners.

ARTICLE VI

Managing General Partner

6.01 Managing General Partner. The Managing General Partner shall have the sole and exclusive right and power to manage and control the affairs of and to operate the Partnership and to do all things necessary to carry on the business of the Partnership for the purposes described in Section 1.03 hereof and to conduct the activities of the Partnership as set forth in Article V hereof. No financial institution or any other person, firm, or corporation dealing with the Managing General Partner shall be required to ascertain whether the Managing General Partner is acting in accordance with this Agreement, but such financial institution or such other person, firm, or corporation shall be protected in relying solely upon the deed, transfer, or assurance of and the execution of such instrument or instruments by the Managing General Partner. The Managing General Partner shall devote so much of its time to the business of the Partnership as in its judgment the conduct of the Partnership’s business shall reasonably require and shall not be obligated to do or perform any act or thing in connection with the business of the Partnership not expressly set forth herein. The Managing General Partner may engage in business ventures of any nature and description independently or with others and neither the Partnership nor any of its Investor Partners shall have any rights in and to such independent ventures or the income or profits derived therefrom. However, except as otherwise provided herein, the Managing General Partner and any of its Affiliates may pursue business opportunities that are consistent with the Partnership’s investment objectives for their own account only after they have determined that such opportunity either cannot be pursued by the Partnership because of insufficient funds or because it is not appropriate for the Partnership under the existing circumstances.

6.02 Authority of Managing General Partner. The Managing General Partner is specifically authorized and empowered, on behalf of the Partnership, and by consent of the Investor Partners herein given, to do any act or execute any document or enter into any contract or any agreement of any nature necessary or desirable, in the opinion of the Managing General Partner, in pursuance of the purposes of the Partnership. Without limiting the generality of the foregoing, in addition to any and all other powers conferred upon the Managing General Partner pursuant to this Agreement and the Act, and except as otherwise prohibited by law or hereunder, the Managing General Partner shall have the power and authority to:

(a) Acquire leases and other interests in oil and/or gas properties in furtherance of the Partnership’s business;

(b) Enter into and execute pooling agreements, farm out agreements, operating agreements, unitization agreements, dry and bottom hole and acreage contribution letters, construction contracts, and any and all documents or instruments customarily employed in the oil and gas industry in connection with the acquisition, sale, exploration, development, or operation of oil and gas properties, and all other instruments deemed by the Managing General Partner to be necessary or appropriate to the proper operation of oil or gas properties or to effectively and properly perform its duties or exercise its powers hereunder;

(c) Make expenditures and incur any obligations it deems necessary to implement the purposes of the Partnership; employ and retain such personnel as it deems desirable for the conduct of the Partnership’s activities, including employees, consultants, and attorneys; and exercise on behalf of the Partnership, in such manner as the Managing General Partner in its sole judgment deems best, of all rights, elections, and obligations granted to or imposed upon the Partnership;

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(d) Manage, operate, and develop any Partnership property, and enter into operating agreements with respect to properties acquired by the Partnership, including an operating agreement with the Managing General Partner as described in the Prospectus, which agreements may contain such terms, provisions, and conditions as are usual and customary within the industry and as the Managing General Partner shall approve;

(e) Compromise, sue, or defend any and all claims in favor of or against the Partnership;

(f) Subject to the provisions of Section 8.04 hereof, make or revoke any election permitted the Partnership by any taxing authority;

(g) Perform any and all acts it deems necessary or appropriate for the protection and preservation of the Partnership assets;

(h) Maintain at the expense of the Partnership such insurance coverage for public liability, fire and casualty, and any and all other insurance necessary or appropriate to the business of the Partnership in such amounts and of such types as it shall determine from time to time;

(i) Buy, sell, or lease property or assets on behalf of the Partnership;

(j) Enter into agreements to hire services of any kind or nature;

(k) Assign interests in properties to the Partnership;

(l) Enter into soliciting dealer agreements and perform all of the Partnership’s obligations thereunder, to issue and sell Units pursuant to the terms and conditions of this Agreement, the Subscription Agreements, and the Prospectus, to accept and execute on behalf of the Partnership Subscription Agreements, and to admit original and substituted Partners; and

(m) Perform any and all acts, and execute any and all documents it deems necessary or appropriate to carry out the purposes of the Partnership.

6.03 Certain Restrictions on Managing General Partner’s Power and Authority. Notwithstanding any other provisions of this Agreement to the contrary, neither the Managing General Partner nor any Affiliate of the Managing General Partner shall have the power or authority to, and shall not, do, perform, or authorize any of the following:

(a) Borrow any money in the name or on behalf of the Partnership;

(b) Use any revenues from Partnership operations for the purposes of acquiring Leases in new or unrelated Prospects or paying any Organization and Offering Expenses; provided, however, that revenues from Partnership operations may be used for other Partnership operations, including without limitation for the purposes of drilling, completing, maintaining, recompleting, and operating wells on existing Partnership Prospects and acquiring and developing new Leases to the extent such Leases are considered by the Managing General Partner in its sole discretion to be a part of a Prospect in which the Partnership then owns a Lease;

(c) Without having first received the prior consent of the holders of a majority of the then outstanding Units entitled to vote,

(i) sell all or substantially all of the assets of the Partnership (except upon liquidation of the Partnership pursuant to Article IX hereof), unless cash funds of the Partnership are insufficient to pay the obligations and other liabilities of the Partnership;

(ii) dispose of the good will of the Partnership;

(iii) do any other act which would make it impossible to carry on the ordinary business of the Partnership; or

(iv) agree to the termination or amendment of any operating agreement to which the Partnership is a party, or waive any rights of the Partnership thereunder, except for amendments to the operating agreement which the Managing General Partner believes are necessary or advisable to ensure that

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the operating agreement conforms to any changes in or modifications to the Code or that do not adversely affect the Investor Partners in any material respect;

(d) Guarantee in the name or on behalf of the Partnership the payment of money or the performance of any contract or other obligation of any Person other than the Partnership;

(e) Bind or obligate the Partnership with respect to any matter outside the scope of the Partnership business;

(f) Use the Partnership name, credit, or property for other than Partnership purposes;

(g) Take any action, or permit any other person to take any action, with respect to the assets or property of the Partnership which does not benefit the Partnership, including, among other things, utilization of funds of the Partnership as compensating balances for its own benefit or the commitment of future production;

(h) Benefit from any arrangement for the marketing of oil and gas production or other relationships affecting the property of the Managing General Partner and the Partnership, unless such benefits are fairly and equitably apportioned among the Managing General Partner, its Affiliates, and the Partnership;

(i) Utilize Partnership funds to invest in the securities of another person except in the following instances:

(1) investments in working interests or undivided lease interests made in the ordinary course of the Partnership’s business;

(2) temporary investments made in compliance with Section 2.02(f) of this Agreement;

(3) investments involving less than 5% of Partnership capital which are a necessary and incidental part of a property acquisition transaction; and

(4) investments in entities established solely to limit the Partnership’s liabilities associated with the ownership or operation of property or equipment, provided, in such instances duplicative fees and expenses shall be prohibited; or

(j) Sell, transfer, or assign its interest (except for a collateral assignment which may be granted to a bank or other financial institution) in the Partnership, or any part thereof, or otherwise to withdraw as Managing General Partner of the Partnership without one hundred twenty (120) days prior written notice to and the written consent of Investor Partners owning a majority of the then outstanding Units.

6.04 Indemnification of Managing General Partner. The Managing General Partner shall have no liability to the Partnership or to any Investor Partner for any loss suffered by the Partnership which arises out of any action or inaction of the Managing General Partner if the Managing General Partner, in good faith, determined that such course of conduct was in the best interest of the Partnership, that the Managing General Partner was acting on behalf of or performing services for the Partnership, and that such course of conduct did not constitute negligence or misconduct of the Managing General Partner. The Managing General Partner shall be indemnified by the Partnership against any losses, judgments, liabilities, expenses, and amounts paid in settlement of any claims sustained by it in connection with the Partnership, provided that the Managing General Partner has determined in good faith that the course of conduct which caused the loss or liability was in the best interests of the Partnership, that the Managing General Partner was acting on behalf of or performing services for the Partnership, and that the same were not the result of negligence or misconduct on the part of the Managing General Partner. Indemnification of the Managing General Partner is recoverable only from the tangible net assets of the Partnership, including the insurance proceeds from the Partnership’s insurance policies and the insurance and indemnification of the Partnership’s subcontractors, and is not recoverable from the Investor Partners.

Notwithstanding the above, the Managing General Partner and any person acting as a broker-dealer shall not be indemnified for liabilities arising under Federal and state securities laws unless (a) there has been a successful adjudication on the merits of each count involving securities law violations, (b) such claims have been dismissed with prejudice on the merits by a court of competent jurisdiction, or (c) a court of competent jurisdiction approves a settlement of such claims against a particular indemnitee and finds that indemnification of the settlement and the related costs should be made, and the court considering the request for indemnification has been advised of the

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position of the Securities and Exchange Commission and of any state securities regulatory authority in which securities of the Partnership were offered or sold as to indemnification for violations of securities laws; provided, however, the court need only be advised of the positions of the securities regulatory authorities of those states (i) which are specifically set forth in the program agreement and (ii) in which plaintiffs claim they were offered or sold program units.

In any claim for indemnification for Federal or state securities laws violations, the party seeking indemnification shall place before the court the position of the Securities and Exchange Commission, the Massachusetts Securities Division, and the Tennessee Securities Division or respective state securities division, as the case may be, with respect to the issue of indemnification for securities law violations.

The advancement of Partnership funds to a sponsor or its affiliates for legal expenses and other costs incurred as a result of any legal action for which indemnification is being sought is permissible only if the Partnership has adequate funds available and the following conditions are satisfied:

(a) the legal action relates to acts or omissions with respect to the performance of duties or services on behalf of the Partnership, and

(b) the legal action is initiated by a third party who is not a participant, or the legal action is initiated by a participant and a court of competent jurisdiction specifically approves such advancement, and

(c) the sponsor or its affiliates undertake to repay the advanced funds to the Partnership, together with the applicable legal rate of interest thereon, in cases in which such party is found not to be entitled to indemnification.

The Partnership shall not incur the cost of the portion of any insurance which insures the Managing General Partner against any liability as to which the Managing General Partner is herein prohibited from being indemnified.

6.05 Withdrawal.

(a) Notwithstanding the limitations contained in Section 6.03(j) hereof, the Managing General Partner shall have the right, by giving written notice to the other Partners, to substitute in its stead as managing general partner any successor entity or any entity controlled by the Managing General Partner, provided that the successor Managing General Partner must have a tangible net worth of at least $5 million, and the Investor Partners, by execution of this Agreement, expressly consent to such a transfer, unless it would adversely affect the status of the Partnership as a partnership for federal income tax purposes.

(b) The Managing General Partner may not voluntarily withdraw from the Partnership prior to the Partnership’s completion of its primary drilling and/or acquisition activities, and then only after giving 120 days written notice. The Managing General Partner may not partially withdraw its property interests held by the Partnership unless such withdrawal is necessary to satisfy the bona fide request of its creditors or approved by a majority-in-interest vote of the Investor Partners. The Managing General Partner shall fully indemnify the Partnership against any additional expenses which may result from a partial withdrawal of property interests and such withdrawal may not result in a greater amount of direct costs or administrative costs being allocated to the Investor Partners. The withdrawing Managing General Partner shall pay all expenses incurred as a result of its withdrawal.

6.06 Management Fee. The Partnership shall pay the Managing General Partner, on the date the Partnership is organized (as set forth in Section 1.01), a one-time management fee equal to 22% of the total Subscriptions.

6.07 Tax Matters and Financial Reporting Partner. The Managing General Partner shall serve as the Tax Matters Partner for purposes of Code Sections 6221 through 6233 and as the Financial Reporting Partner. The Partnership may engage its accountants and/or attorneys to assist the Tax Matters Partner in discharging its duties hereunder.

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ARTICLE VII

Investor Partners

7.01 Management. No Investor Partner shall take part in the control or management of the business or transact any business for the Partnership, and no Investor Partner shall have the power to sign for or bind the Partnership. Any action or conduct of Investor Partners on behalf of the Partnership is hereby expressly prohibited. Any Investor Partner who violates this Section 7.01 shall be liable to the remaining Investor Partners, the Managing General Partner, and the Partnership for any damages, costs, or expenses any of them may incur as a result of such violation. The Investor Partners hereby grant to the Managing General Partner or its successors or assignees the exclusive authority to manage and control the Partnership business in its sole discretion and to thereby bind the Partnership and all Partners in its conduct of the Partnership business. Investor Partners shall have the right to vote only with respect to those matters specifically provided for in these Articles. No Investor Partner shall have the authority to:

(a) Assign the Partnership property in trust for creditors or on the assignee’s promise to pay the debts of the Partnership;

(b) Dispose of the goodwill of the business;

(d) Confess a judgment;

(e) Submit a Partnership claim or liability to arbitration or reference;

(f) Make a contract or bind the Partnership to any agreement or document;

(g) Use the Partnership’s name, credit, or property for any purpose;

(h) Do any act which is harmful to the Partnership’s assets or business or by which the interests of the Partnership shall be imperiled or prejudiced; or

(i) Perform any act in violation of any applicable law or regulations thereunder, or perform any act which is inconsistent with the terms of this Agreement.

7.02 Indemnification of Additional General Partners. The Managing General Partner agrees to indemnify each of the Additional General Partners for the amounts of obligations, risks, losses, or judgments of the Partnership or the Managing General Partner which exceed the amount of applicable insurance coverage and amounts which would become available from the sale of all Partnership assets. Such indemnification applies to casualty losses and to business losses, such as losses incurred in connection with the drilling of an unproductive well, to the extent such losses exceed the Additional General Partners’ interest in the undistributed net assets of the Partnership. If, on the other hand, such excess obligations are the result of the negligence or misconduct of an Additional General Partner, or the contravention of the terms of the Partnership Agreement by the Additional General Partner, then the foregoing indemnification by the Managing General Partner shall be unenforceable as to such Additional General Partner and such Additional General Partner shall be liable to all other Partners for damages and obligations resulting therefrom.

7.03 Assignment of Units.

(a) An Investor Partner may transfer all or any portion of his Units and the transferee shall become a Substituted Investor Partner (subject to all duties and obligations of an Investor Partner, including those contained in Section 4.04 herein, except to the extent excepted in the Act) subject to the following conditions (any transfer of such Units satisfying such conditions being referred to herein as a “Permitted Transfer”):

(i) Except in the case of a transfer of Units at death or involuntarily by operation of law, the transferor and transferee shall execute and deliver to the Partnership such documents and instruments of conveyance as may be necessary or appropriate in the opinion of counsel to the Partnership to effect such transfer and to confirm the agreement of the transferee to be bound by the provisions of this Article VII. In any case not described in the preceding sentence, the transfer shall be confirmed by presentation to the Partnership of legal evidence of

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such transfer, in form and substance satisfactory to counsel to the Partnership. In all cases, the Partnership shall be reimbursed by the transferor and/or transferee for all costs and expenses that it reasonably incurs in connection with such transfer;

(ii) The transferor and transferee shall furnish the Partnership with the transferee’s taxpayer identification number and sufficient information to determine the transferee’s initial tax basis in the Units transferred; and

(iii) The written consent of the Managing General Partner to such transfer shall have been obtained.

(b) A Person who acquires one or more Units but who is not admitted as a Substituted Investor Partner pursuant to Section 7.03(c) hereof shall be entitled only to allocations and distributions with respect to such Units in accordance with this Agreement, but shall have no right to any information or accounting of the affairs of the Partnership, shall not be entitled to inspect the books or records of the Partnership, and shall not have any of the rights of an Additional General Partner or a Limited Partner under the Act or the Agreement.

(c) Subject to the other provisions of this Article VII, a transferee of Units may be admitted to the Partnership as a Substituted Investor Partner only upon satisfaction of the conditions set forth below in this Section 7.03(c):

(i) The Managing General Partner consents to such admission;

(ii) The Units with respect to which the transferee is being admitted were acquired by means of a Permitted Transfer;

(iii) The transferee becomes a party to this Agreement as a Partner and executes such documents and instruments as the Managing General Partner may reasonably request (including, without limitation, amendments to the Certificate of Limited Partnership) as may be necessary or appropriate to confirm such transferee as a Partner in the Partnership and such transferee’s agreement to be bound by the terms and conditions hereof;

(iv) The transferee pays or reimburses the Partnership for all reasonable legal, filing, and publication costs that the Partnership incurs in connection with the admission of the transferee as a Partner with respect to the transferred Units; and

(v) If the transferee is not an individual of legal majority, the transferee provides the Partnership with evidence satisfactory to counsel for the Partnership of the authority of the transferee to become a Partner and to be bound by the terms and conditions of this Agreement.

(vi) In any calendar quarter in which a Substituted Investor Partner is admitted to the Partnership, the Managing General Partner shall amend the certificate of limited partnership to effect the substitution of such Substituted Investor Partners, although the Managing General Partner may do so more frequently. In the case of assignments, where the assignee does not become a Substituted Investor Partner, the Partnership shall recognize the assignment not later than the last day of the calendar month following receipt of notice of assignment and required documentation.

(d) Each Investor Partner hereby covenants and agrees with the Partnership for the benefit of the Partnership and all Partners that (i) he is not currently making a market in Units and (ii) he will not transfer any Unit on an established securities market or a secondary market (or the substantial equivalent thereof) within the meaning of Code Section 7704(b) (and any regulations, proposed regulations, revenue rulings, or other official pronouncements of the Service or Treasury Department that may be promulgated or published thereunder). Each Investor Partner further agrees that he will not transfer any Unit to any Person unless such Person agrees to be bound by this Section 7.03 and to transfer such Units only to Persons who agree to be similarly bound.

(e) Restrictions on assignment of Units or the substitution of Investor Partners shall be allowed only to the extent necessary to preserve the tax status of the Partnership or the classification of Partnership income for tax purposes and any restriction shall be supported by an opinion of the Partnership’s counsel as to its legal necessity.

7.04 Prohibited Transfers.

(a) Any purported Transfer of Units that is not a Permitted Transfer shall be null and void and of no effect whatever; provided, that, if the Partnership is required to recognize a transfer that is not a Permitted Transfer (or if

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the Managing General Partner, in its sole discretion, elects to recognize a transfer that is not a Permitted Transfer), the interest transferred shall be strictly limited to the transferor’s rights to allocations and distributions as provided by this Agreement with respect to the transferred Units, which allocations and distributions may be applied (without limiting any other legal or equitable rights of the Partnership) to satisfy the debts, obligations, or liabilities for damages that the transferor or transferee of such Units may have to the Partnership.

(b) In the case of a transfer or attempted transfer of Units that is not a Permitted Transfer, the parties engaging or attempting to engage in such transfer shall be liable to indemnify and hold harmless the Partnership and the other Partners from all cost, liability, and damage that any of such indemnified Persons may incur (including, without limitation, incremental tax liability and lawyers’ fees and expenses) as a result of such transfer or attempted transfer and efforts to enforce the indemnity granted hereby.

7.05 Withdrawal by Investor Partners. Neither a Limited Partner nor an Additional General Partner may withdraw from the Partnership, except as otherwise provided in this Agreement.

7.06 Removal of Managing General Partner.

(a) The Managing General Partner may be removed at any time with the consent of Investor Partners owning a majority of the then outstanding Units, and upon the selection of a successor managing general partner or partners by Investor Partners owning a majority of the then outstanding Units.

(b) Any successor Managing General Partner may be removed upon the terms and conditions provided in this Section.

(c) In the event a managing general partner is removed, its respective interest in the assets of the Partnership shall be determined by independent appraisal by a qualified independent petroleum engineering consultant who shall be selected by mutual agreement of the Managing General Partner and the incoming sponsor. Such appraisal will take into account an appropriate discount to reflect the risk of recovery of oil and gas reserves, and, at its election, the removed managing general partner’s interest in the Partnership assets may be distributed to it or the interest of the managing general partner in the Partnership may be retained by it as a Limited Partner in the successor limited partnership; provided, however, that if immediate payment to the removed managing general partner would impose financial or operational hardship upon the Partnership, as determined by the successor managing general partner in the exercise of its fiduciary duties to the Partnership, payment (plus reasonable interest) to the removed managing general partner may be postponed to that time when, in the determination of the successor managing general partner, payment will not cause a hardship to the Partnership. The cost of such appraisal shall be borne by the Partnership. The successor managing general partner shall have the option to purchase at least 20% of the removed managing general partner’s interest for the value determined by the independent appraisal. The removed managing general partner, at the time of its removal shall cause, to the extent it is legally possible, its successor to be transferred or assigned all its rights, obligations, and interests in contracts entered into by it on behalf of the Partnership. In any event, the removed managing general partner shall cause its rights, obligations, and interests in any such contract to terminate at the time of its removal.

(d) Upon effectiveness of the removal of the managing general partner, the assets, books, and records of the Partnership shall be surrendered to the successor managing general partner, provided that the successor managing general partner shall have first (i) agreed to accept the responsibilities of the managing general partner, and (ii) made arrangements satisfactory to the original managing general partner to remove such managing general partner from personal liability on any Partnership borrowings or, if any Partnership creditor will not consent to such removal, agreed to indemnify the original managing general partner for any subsequent liabilities in respect to such borrowings. Immediately after the removal of the managing general partner, the successor managing general partner shall prepare, execute, file for recordation, and cause to be published, such notices or certificates as may be required by the Act.

7.07 Calling of Meetings. Investor Partners owning 10% or more of the then outstanding Units entitled to vote shall have the right to request that the Managing General Partner call a meeting of the Partners. The Managing General Partner shall call such a meeting and shall deposit in the United States mails within fifteen days after receipt of such request, written notice to all Investor Partners of the meeting and the purpose of the meeting, which shall be held on a date not less than thirty nor more than sixty days after the date of mailing of such notice, at a reasonable

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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; but any such amendment may not increase the duties or liabilities of any Investor Partner or the Managing General Partner or increase or decrease the profit or loss sharing or required capital contribution of any Investor Partner or the Managing General Partner without the approval of such Investor Partner or Managing General Partner; and any such amendment may not affect the classification of the Partnership’s income or loss for federal income tax purposes without the unanimous approval of all Investor Partners, (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 662/3% in interest of the Investor Partners. A majority in interest of the then outstanding Units entitled to vote shall constitute a quorum. In determining the requisite percentage in interest of Units necessary to approve a matter on which the Managing General Partner and its Affiliates may not vote or consent, any Units owned by the Managing General Partner and its Affiliates shall not be included. With respect to the merger or consolidation of the Partnership or the sale of all or substantially all of the assets of the Partnership, Investor Partners shall have the right to exercise dissenter’s rights in accordance with Section 31-1-123 of the West Virginia Corporation Law.

7.09 Voting by Proxy. The Investor Partners may vote either in person or by proxy.

7.10 Conversion of Additional General Partner Interests into Limited Partner Interests.

(a) As provided herein, Additional General Partners may elect to convert, transfer, and exchange their interests for Limited Partner interests in the Partnership upon receipt by the Managing General Partner of written notice of such election. An Additional General Partner may request conversion of his interests for Limited Partner interests at any time after one year following the closing of the securities offering which relates to the Agreement and the disbursement to the Partnership of the proceeds of such securities offering.

(b) The Managing General Partner shall notify all Additional General Partners at least 30 days prior to any material change in the amount of the Partnership’s insurance coverage. Within this 30-day period, and notwithstanding Section 7.10(a), Additional General Partners shall have the right to immediately convert their Units into Units of limited partnership interest by giving written notice to the Managing General Partner.

(c) The Managing General Partner shall convert the interests of all Additional General Partners in a particular Partnership to interests of Limited Partners in that Partnership upon completion of drilling of that Partnership.

(d) The Managing General Partner shall cause the conversion to be effected as promptly as possible as prudent business judgment dictates. Conversion of an Additional General Partnership interest to a Limited Partnership interest in a particular Partnership shall be conditioned upon a finding by the Managing General Partner that such conversion will not cause a termination of the Partnership for federal income tax purposes, and will be effective upon the Managing General Partner’s filing an amendment to its Certificate of Limited Partnership. The Managing General Partner is obligated to file an amendment to its Certificate at any time during the full calendar month after receipt of the required notice of the Additional General Partner and a determination of the Managing General Partner that the conversion will not constitute a termination of the Partnership for tax purposes. Effecting conversion is subject to the satisfaction of the condition that the electing Additional General Partner provide written notice to the Managing General Partner of such intent to convert. Upon such transfer and exchange, such Additional General

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Partners shall be Limited Partners; however, they will remain liable to the Partnership for any additional Capital Contribution(s) required for their proportionate share of any Partnership obligation or liability arising prior to the conversion.

(e) Limited Partners may not convert and/or exchange their interests for Additional General Partner interests.

7.11 Unit Repurchase Program.

(a) Beginning with the third anniversary of the date of the first cash distribution of the Partnership, Investor Partners may tender their Units to the Managing General Partner for repurchase, subject to the Managing General Partner’s available borrowing capacity under its loan agreements to repurchase and the Managing General Partner’s receipt of an opinion of counsel that the Managing General Partner’s repurchase of Units pursuant to this Section will not cause the Partnership to be treated as a “publicly traded partnership” for purposes of Code Sections 469 and 7704. Failure to receive such opinion shall preclude the Managing General Partner from making any offers to repurchase Units. Subject to such borrowing capacity and legal opinion, the Managing General Partner shall offer to annually repurchase for cash a minimum of 10% of the Units originally subscribed to in the Partnership.

(b) The Unit Repurchase Program shall be subject to the following conditions:

(i) The Managing General Partner must receive written notification from the particular Investor Partner of such Partner’s intention to exercise the repurchase right; and

(ii) The Managing General Partner shall provide the Investor Partner a written offer of a specified price for purchase of the particular Units within 30 days of the Managing General Partner’s receipt of written notification; and

(iii) The Managing General Partner’s offer shall remain open for 30 days after the Managing General Partner’s mailing of the offer to the Investor Partner.

(c) The Managing General Partner shall not favor one particular Partnership of which it is a Managing General Partner over another in the repurchase of Units. Each Partnership shall stand on equal footing before the Managing General Partner. To the extent that the Managing General Partner is unable, due to limitations imposed by the Code or 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.

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ARTICLE VIII

Books and Records

8.01 Books and Records.

(a) For accounting and income tax purposes, the Partnership shall operate on a calendar year.

(b) The Managing General Partner shall keep just and true records and books of account with respect to the operations of the Partnership and shall maintain and preserve during the term of the Partnership and for four years thereafter all such records, books of account, and other relevant Partnership documents. The Managing General Partner shall maintain for at least six years all records necessary to substantiate the fact that Units were sold only to purchasers for whom such Units were suitable. Such books shall be maintained at the principal place of business of the Partnership and shall be kept on the accrual method of accounting.

(c) The Managing General Partner shall keep or cause to be kept complete and accurate books and records with respect to the Partnership’s business, which books and records shall at all times be kept at the principal office of the Partnership. Any records maintained by the Partnership in the regular course of its business, including the names and addresses of Investor Partners, books of account, and records of Partnership proceedings, may be kept on or be in the form of RAM disks, magnetic tape, photographs, micrographics, or any other information storage device, provided that the records so kept are convertible into clearly legible written form within a reasonable period of time. The books and records of the Partnership shall be made available for review and copying by any Investor Partner or his representative at any reasonable time.

(d) (i) An alphabetical list of the names, addresses and business telephone numbers of the Investor Partners of the Partnership along with the number of Units held by each of them (the “participant list”) shall be maintained as a part of the books and records of the Partnership and shall be available for the inspection by any Investor Partner or its designated agent at the home office of the Partnership upon the request of the Investor Partner;

(ii) The participant list shall be updated at least quarterly to reflect changes in the information contained therein;

(iii) A copy of the participant list shall be mailed to any Investor Partner requesting the participant list within ten days of the request. The copy of the participant list shall be printed in alphabetical order, on white paper, and in a readily readable type size (in no event smaller than l0-point type). A reasonable charge for copy work may be charged by the Partnership.

(iv) The purposes for which an Investor Partner may request a copy of the participant list include, without limitation, matters relating to voting rights under the Partnership Agreement and the exercise of Investor Partners’ rights under federal proxy laws; and

(v) If the Managing General Partner of the Partnership neglects or refuses to exhibit, produce, or mail a copy of the participant list as requested, the Managing General Partner shall be liable to any Investor Partner requesting the list for the costs, including attorneys’ fees, incurred by that Investor Partner for compelling the production of the participant list, and for actual damages suffered by any Investor Partner by reason of such refusal or neglect. It shall be a defense that the actual purpose and reason for the requests for inspection or for a copy of the participant list is to secure the list of Investor Partners or other information for the purpose of selling such list or information or copies thereof, or of using the same for a commercial purpose other than in the interest of the applicant as an Investor Partner relative to the affairs of the Partnership. The Managing General Partner may require the Investor Partner requesting the participant list to represent that the list is not requested for a commercial purpose unrelated to the Investor Partner’s interest in the Partnership. The remedies provided hereunder to Investor Partners requesting copies of the participant list are in addition to, and shall not in any way limit, other remedies available to Investor Partners under federal law, or the laws of any state.

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

(a) Within 75 days after the end of the first six months of each fiscal year (for such six month period) and within 120 days after the end of each fiscal year (for such year), financial statements, including a balance sheet

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and statements of income, Partners’ equity, and cash flows, all of which shall be prepared in accordance with generally accepted accounting principles. The annual financial statements shall be accompanied by (i) a report of an independent certified public accountant designated by the Managing General Partner stating that an audit of such financial statements has been made in accordance with generally accepted auditing standards and that in its opinion such financial statements present fairly the financial condition, results of operations, and cash flow of the Partnership in accordance with generally accepted accounting principles and (ii) a reconciliation of such financial statements with the information furnished to the Investor Partners for federal income tax reporting purposes.

(b) Annually by March 15 of each year, a report containing such information as may be deemed to enable each Investor Partner to prepare and file his federal income tax return and any required state income tax return.

(c) Annually within 120 days after the end of each fiscal year, (i) a summary of the computations of the total estimated proved oil and gas reserves of the Partnership as of the end of such fiscal year and the dollar value thereof at then existing prices and a computation of each Investor Partner’s interest in such value, such reserve computations to be based upon engineering reports prepared by qualified independent petroleum engineers, (ii) an estimate of the time required for the extraction of such proved reserves and the present worth thereof (discounted at a rate generally accepted in the oil and gas industry and undiscounted), and (iii) a statement that because of the time period required to extract such reserves the present value of revenues to be obtained in the future is less than if such revenues were immediately receivable. Each such reported shall be prepared in accordance with customary and generally accepted standards and practices for petroleum engineers and shall be prepared by a recognized independent petroleum engineer selected from time to time by the Managing General Partner. No later than 90 days following the occurrence of an event resulting in a reduction in an amount of 10% or more of the estimated value of the proved oil and gas reserves as last reported to the Investor Partners, other than a reduction resulting from normal production, sales of reserves, or product price changes, a new summary conforming to the requirements set forth above in this Section 8.02(c) shall be delivered to the Investor Partners.

(d) Within 75 days after the end of the first six months of each fiscal year and within 120 days after the end of each fiscal year, (i) a summary itemization, by type and/or classification, of any transaction of the Partnership since the date of the last such report with the Managing General Partner or any Affiliate thereof and the total fees, compensation, and reimbursement paid by the Partnership (or indirectly on behalf of the Partnership) to the Managing General Partner and its Affiliates, and (ii) a schedule reflecting (A) the total costs of the Partnership (and, where applicable, the costs pertaining to each Lease) and the costs paid by the Managing General Partner and by the Investor Partners and (B) the total revenues of the Partnership and the revenues received by or credited to the accounts of the Managing General Partner and the Investing Partners. Each semi-annual report delivered by the Managing General Partner may contain summary estimates of the information described in subdivision (i) of Section 8.02(c).

(e) Monthly within 15 days after the end of each calendar month while the Partnership is participating in the drilling and completion of wells in which it has an interest until the end of such activity, and thereafter for a period of three years within 75 days after the end of the first six months of each fiscal year and within 120 days after the end of each fiscal year, (i) a description of each Prospect or field in which the Partnership owns Leases including the cost, location, number of acres under lease, and the interest owned therein by the program (provided that after the initial description of each such Prospect or field has been provided to the Investor Partners only material changes, if any, with respect to such Prospect or field need be described), (ii) a description of all farmins, farmouts and joint ventures of the Partnership made since the date of the last such report, including the reason therefor, the location and timing thereof, the person to whom made and the terms thereof, and (iii) a summary of the wells drilled by the Partnership, indicating whether each of such wells has been completed, a statement of the cost of each well completed or abandoned and the reason for abandoning any well after commencement of production. Each report delivered by the Managing General Partner may contain summary estimates of the information described in subsection (iii).

(f) The Managing General Partner shall cause the Partnership’s independent auditors to audit the financial statements of the Partnership in accordance with generally accepted auditing standards. An audit

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includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, which would include an assessment as to whether or not the method used to make the allocations of costs was consistent with the method described in the Prospectus. If the Managing General Partner subsequently decides to allocate expenses in a manner different from the manner described in the Prospectus, such change shall be reported by the Managing General Partner to the Investor Partners together with an explanation of why such change was made and the basis for determining the reasonableness of the new allocation method.

(g) Such other reports and financial statements as the Managing General Partner shall determine from time to time.

(h) Concurrently with their transmittal to Investor Partners and as required, the Managing General Partner shall file a copy of each such report with the California Commissioner of Corporations and with the securities divisions of other states.

8.03 Bank Accounts. All funds of the Partnership shall be deposited in such separate bank account or accounts, short term obligations of the U.S. Government or its agencies, or other interest-bearing investments and money market or liquid asset mutual funds as shall be determined by the Managing General Partner. All withdrawals therefrom shall be made upon checks signed by the Managing General Partner or any person authorized to do so by the Managing General Partner.

8.04 Federal Income Tax Elections.

(a) Except as otherwise provided in this Section 8.04, all elections required or permitted to be made by the Partnership under the Code shall be made by the Managing General Partner in its sole discretion. Each Partner agrees to provide the Partnership with all information necessary to give effect to any election to be made by the Partnership.

(b) The Partnership shall elect to currently deduct IDC as an expense for income tax purposes and shall require any partnership, joint venture, or other arrangement in which it is a party to make such an election.

ARTICLE IX

Dissolution; Winding-up

9.01 Dissolution.

(a) Except as otherwise provided herein, the retirement, withdrawal, removal, death, insanity, incapacity, dissolution, or bankruptcy of any Investor Partner shall not dissolve the Partnership. The successor to the rights of such Investor Partner shall have all the rights of an Investor Partner for the purpose of settling or administering the estate or affairs of such Investor Partner; provided, however, that no successor shall become a substituted Investor Partner except in accordance with Article VII hereof; provided, further, that upon the withdrawal of an Additional General Partner, the Partnership shall be dissolved and wound up unless at that time there is at least one other General Partner, in which event the business of the Partnership shall continue to be carried on. Neither the expulsion of any Investor Partner nor the admission or substitution of an Investor Partner shall work a dissolution of the Partnership. The estate of a deceased, insane, incompetent, or bankrupt Investor Partner shall be liable for all his liabilities as an Investor Partner.

(b) The Partnership shall be dissolved upon the earliest to occur of: (i) the written consent of the Investor Partners owning a majority of the then-outstanding Units to dissolve and wind up the affairs of the Partnership; (ii) subject to the provisions of Subsection (c) below, the retirement, withdrawal, removal, death, adjudication of insanity or incapacity, or bankruptcy (or, in the case of a corporate managing general partner, the withdrawal, removal, filing of a certificate of dissolution, liquidation, or bankruptcy) of the Managing General Partner; (iii) the sale, forfeiture, or abandonment of all or substantially all of the Partnership’s property; (iv) December 31, 2050; (v) a dissolution event described in Subsection (a) above; or (vi) any event causing dissolution of the Partnership under the Act.

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(c) In the case of any event described in Subsection (b)(ii) above, if a successor Managing General Partner is selected by Partners owning a majority of the then outstanding Units within ninety (90) days after such 9.01(b)(ii) event, and if such Investor Partners agree, within such 90 day period to continue the business of the Partnership, or if the remaining managing general partner, if any, continues the business of the Partnership, then the Partnership shall not be dissolved.

(d) If the retirement, withdrawal, removal, death, insanity, incapacity, dissolution, liquidation, or bankruptcy of any Partner, or the assignment of a Partner’s interest in the Partnership, or the substitution or admission of a new Partner, shall be deemed under the Act to cause a dissolution of the Partnership, then, except as provided in Section 9.01(c), the remaining Partners may, in accordance with the Act, continue the Partnership business as a new partnership and all such remaining Partners agree to be bound by the provisions of this Agreement.

9.02 Liquidation. Upon a dissolution and final termination of the Partnership, the Managing General Partner, or in the event there is no Managing General Partner, any other person or entity selected by the Investor Partners (hereinafter referred to as a “Liquidator”) shall cause the affairs of the Partnership to be wound up and shall take account of the Partnership’s assets (including contributions, if any, of the Managing General Partner pursuant to Section 3.01(e) herein) and liabilities, and the assets shall, subject to the provisions of Section 9.03(b) herein, be liquidated as promptly as is consistent with obtaining the fair market value thereof, and the proceeds therefrom (which dissolution and liquidation may be accomplished over a period spanning one or more tax years in the sole discretion of the Managing General Partner or Liquidator), to the extent sufficient therefor, shall be applied and distributed in accordance with Section 9.03.

9.03 Winding-up.

(a) Upon the dissolution of the Partnership and winding up of its affairs, the assets of the Partnership shall be distributed as follows:

(i) all of the Partnership’s debts and liabilities to persons other than the Managing General Partner shall be paid and discharged;

(ii) all outstanding debts and liabilities to the Managing General Partner shall be paid and discharged;

(iii) assets shall be distributed to the Partners to the extent of their positive Capital Account balances, pro rata, in accordance with such positive Capital Account balances; and

(iv) any assets remaining after the Partners’ Capital Accounts have been reduced to zero pursuant to Section 9.03(c) herein shall be distributed 80% to the Investor Partners and 20% to the Managing General Partner, except as otherwise revised pursuant to Section 2.01(a) and/or Section 4.02.

(b) Distributions pursuant to this Section 9.03 shall be made in cash or in kind to the Partners, at the election of the Partners. Notwithstanding the provision of this Section 9.03(b), in no event shall the Partners reserve the right to take in kind and separately dispose of their share of production.

(c) Any in kind property distributions to the Investor Partners shall be made to a liquidating trust or similar entity for the benefit of the Investor Partners, unless at the time of the distribution:

(1) the Managing General Partner shall offer the individual Investor Partners the election of receiving in kind property distributions and the Investor Partners accept such offer after being advised of the risks associated with such direct ownership; or

(2) there are alternative arrangements in place which assure the Investor Partners that they will not, at any time, be responsible for the operation or disposition of Partnership properties.

The winding up of the affairs of the Partnership and the distribution of its assets shall be conducted exclusively by the Managing General Partner or the Liquidator, who is hereby authorized to do any and all acts and things authorized by law for these purposes.

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ARTICLE X

Power of Attorney

10.01 Managing General Partner as Attorney-in-Fact. The undersigned makes, constitutes, and appoints the Managing General Partner the true and lawful attorney for the undersigned, and in the name, place, and stead of the undersigned from time to time to make, execute, sign, acknowledge, and file:

(a) Any notices or certificates as may be required under the Act and under the laws of any other state or jurisdiction in which the Partnership shall engage, or seek to engage, to do business and to do such other acts as are required to constitute the Partnership as a limited partnership under such laws.

(b) Any amendment to the Agreement pursuant to and which complies with Section 11.09 herein.

(c) Such certificates, instruments, and documents as may be required by, or may be appropriate under the laws of any state or other jurisdiction in which the Partnership is doing or intends to do business and with the use of the name of the Partnership by the Partnership.

(d) Such certificates, instruments, and documents as may be required by, or as may be appropriate for the undersigned to comply with, the laws of any state or other jurisdiction to reflect a change of name or address of the undersigned.

(e) Such certificates, instruments, and documents as may be required to be filed with the Department of Interior (including any bureau, office or other unit thereof, whether in Washington, D.C. or in the field, or any officer or employee thereof), as well as with any other federal or state agencies, departments, bureaus, offices, or authorities and pertaining to (i) any and all offers to lease, leases (including amendments, modifications, supplements, renewals, and exchanges thereof) of, or with respect to, any lands under the jurisdiction of the United States or any state including without limitation lands within the public domain, and acquired lands, and provides for the leasing thereof; (ii) all statements of interest and holdings on behalf of the Partnership or the undersigned; (iii) any other statements, notices, or communications required or permitted to be filed or which may hereafter be required or permitted to be filed under any law, rule, or regulation of the United States, or any state relating to the leasing of lands for oil or gas exploration or development; (iv) any request for approval of assignments or transfers of oil and gas leases, any unitization or pooling agreements and any other documents relating to lands under the jurisdiction of the United States or any state; and (v) any other documents or instruments which said attorney-in-fact in its sole discretion shall determine should be filed.

(f) Any further document, including furnishing verified copies of the Agreement and/or excerpts therefrom, which said attorney-in-fact shall consider necessary or convenient in connection with any of the foregoing, hereby giving said attorney-in-fact full power and authority to do and perform each and every act and thing whatsoever requisite and necessary to be done in and about the foregoing as fully as the undersigned might and could do if personally present, and hereby ratifying and confirming all that said attorney-in-fact shall lawfully do to cause to be done by virtue hereof.

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

(a) is a special Power of Attorney coupled with an interest, is irrevocable, and shall survive the death of the undersigned;

(b) shall survive the delivery of any assignment by the undersigned of the whole or any portion of his Units; except that where the assignee thereof has been approved by the Managing General Partner for admission to the Partnership as a substitute general or limited Partner as the case may be, the Power of Attorney shall survive the delivery of such assignment for the sole purpose of enabling said attorney-in-fact to execute, acknowledge, and file any instrument necessary to effect such substitution; and

(c) may be exercised by said attorney-in-fact with full power of substitution and resubstitution and may be exercised by a listing of all of the Partners executing any instrument with a single signature of said attorney-in-fact.

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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): to the Managing General Partner, 103 East Main Street, Bridgeport, West Virginia 26330; if to an Investor Partner, at such Investor Partner’s address for purposes of notice which is set forth on Exhibit A attached hereto. Unless otherwise expressly set forth in this Agreement to the contrary, any such notice shall be deemed to be given on the date on which the same was deposited in a regularly maintained receptacle for the deposit of United States mail, addressed and sent as aforesaid.

11.03 Paragraph Headings. The headings in this Agreement are inserted for convenience and identification only and are in no way intended to describe, interpret, define, or limit the scope, extent, or intent of this Agreement or any provision hereof.

11.04 Severability. Every portion of this Agreement is intended to be severable. If any term or provision hereof is illegal or invalid by any reason whatsoever, such illegality or invalidity shall not affect the validity of the remainder of this Agreement.

11.05 Sole Agreement. This Agreement constitutes the entire understanding of the parties hereto with respect to the subject matter hereof and no amendment, modification, or alteration of the terms hereof shall be binding unless the same be in writing, dated subsequent to the date hereof and duly approved and executed by the Managing General Partner and such percentage of Investor Partners as provided in Section 11.09 of this Agreement.

11.06 Applicable Law. This Agreement, which shall be governed exclusively by its terms, is intended to comply with the Code and with the Act and shall be interpreted consistently therewith.

11.07 Execution in Counterparts. This Agreement may be executed in any number of counterparts with the same effect as if all parties hereto had all signed the same document. All counterparts shall be construed together and shall constitute one agreement.

11.08 Waiver of Action for Partition. Each of the parties irrevocably waives, during the term of the Partnership, any right that it may have to maintain any action for partition with respect to the Partnership and the property of the Partnership.

11.09 Amendments.

(a) Unless otherwise specifically herein provided, this Agreement shall not be amended without the consent of the Investor Partners owning a majority of the then outstanding Units entitled to vote.

(b) The Managing General Partner may, without notice to, or consent of, any Investor Partner, amend any provisions of these Articles, or consent to and execute any amendment to these Articles, to reflect:

(i) A change in the name or location of the principal place of business of the Partnership;

(ii) The admission of substituted or additional Investor Partners in accordance with these Articles;

(iii) A reduction in, return of, or withdrawal of, all or a portion of any Investor Partner’s Capital Contribution;

(iv) A correction of any typographical error or omission;

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(v) A change which is necessary in order to qualify the Partnership as a limited partnership under the laws of any other state or which is necessary or advisable, in the opinion of the Managing General Partner, to ensure that the Partnership will be treated as a partnership and not as an association taxable as a corporation for federal income tax purposes;

(vi) A change in the allocation provisions, in accordance with the provisions of Section 3.02(l) herein, in a manner that, in the sole opinion of the Managing General Partner (which opinion shall be determinative), would result in the most favorable aggregate consequences to the Investor Partners as nearly as possible consistent with the allocations contained herein, for such allocations to be recognized for federal income tax purposes due to developments in the federal income tax laws or otherwise; or

(vii) Any other amendment similar to the foregoing;

provided, however, that the Managing General Partner shall have no authority, right, or power under this Section to amend the voting rights of the Investor Partners.

11.10 Consent to Allocations and Distributions. The methods herein set forth by which allocations and distributions are made and apportioned are hereby expressly consented to by each Partner as an express condition to becoming a Partner.

11.11 Ratification. The Investor Partner whose signature appears at the end of this Article hereby specifically adopts and approves every provision of this Agreement to which the signature page is attached.

11.12 Substitution of Signature Pages. This Agreement has been executed in duplicate by the undersigned Investor Partners and one executed copy of the signature page is attached to the undersigned’s copy of this Agreement. It is agreed that the other executed copy of such signature page may be attached to an identical copy of this Agreement together with the signature pages from counterpart Agreements which may be executed by other Investor Partners.

11.13 Incorporation by Reference. Every exhibit, schedule, and other appendix attached to this Agreement and referred to herein is hereby incorporated in this Agreement by reference.

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FIRST AMENDMENT TO LIMITED PARTNERSHIP AGREEMENT

This FIRST AMENDMENT (this “Amendment”) to the Limited Partnership Agreement (the ‘‘Agreement”) of PDC 2002-D Limited Partnership (the “Partnership”) is made as of this day of , 2011. Capitalized terms used but not defined in this Amendment shall have the respective meanings given to such terms in the Agreement. Each reference to “hereof,” “hereunder,” “hereby” and “this Agreement” in the Agreement shall, from and after the date of this Amendment, refer to the Agreement as amended by this Amendment.

WHEREAS, pursuant to Section 11.09 of the Agreement, the Agreement may not be amended without the consent of the Investor Partners owning a majority of the then outstanding Units entitled to vote; and

WHEREAS, at a Special Meeting of the Investor Partners held on , 2011, the Investor Partners approved an amendment to the Agreement as set forth herein;

NOW, THEREFORE, the Managing General Partner of the Partnership amends the Agreement as follows:

Section 7.08 of the Agreement is hereby amended by the addition of the following sentence to the end thereof:

IN WITNESS WHEREOF, the Managing General Partner has caused this Amendment to be duly executed by an authorized officer as of the date first written above.

PETROLEUM DEVELOPMENT CORPORATION,
Managing General Partner


	By:

Name:

Title:

G-2

PDC 2002-D Limited Partnership

Proxy Solicited on Behalf of the Managing General Partner of the Partnership

The undersigned hereby appoints Darwin L. Stump and Celesta Miracle, and either of them, with full power of substitution, proxies to vote all of the limited partnership units (the “Units”) in PDC 2002-D Limited Partnership (the “Partnership”) which the undersigned is entitled to vote at the special meeting of the investors in the Partnership to be held at 1775 Sherman Street, Suite 3000, Denver, Colorado 80203 on October 28, 2011 at 10:00 a.m., local time, or at any adjournment or postponement thereof, with all power which the undersigned would possess if personally present, upon the following proposals, described in the accompanying proxy statement, in accordance with the following instructions. THIS PROXY, WHEN PROPERLY EXECUTED, WILL BE VOTED AS DIRECTED BY THE UNDERSIGNED. IF NO DIRECTION IS INDICATED ON AN OTHERWISE PROPERLY EXECUTED PROXY, THIS PROXY WILL BE VOTED “FOR” THE FOLLOWING PROPOSALS:

1. To approve an amendment to the Partnership’s partnership agreement granting to the investors the express right to consider merger transactions.

[ ] FOR [ ] AGAINST [ ] ABSTAIN

2. To approve the merger agreement by and among Petroleum Development Corporation, or PDC, DP 2004 Merger Sub, LLC, a wholly-owned subsidiary of PDC, and the Partnership, under which the Partnership will merge with and into DP 2004 Merger Sub, LLC, with DP 2004 Merger Sub, LLC being the surviving entity, and pursuant to which the investors will receive a cash payment of $4,024 per limited partnership unit, plus the sum of the amounts withheld from per unit cash distributions by the partnership from October 1, 2010 through August 31, 2011 for the partnership’s additional Codell formation development plan, less the sum of the per unit cash distributions made after August 31, 2011 and before the transaction closes, and after the merger, the separate existence of the Partnership will cease, and PDC will own all the interests in DP 2004 Merger Sub, LLC.

[ ] FOR [ ] AGAINST [ ] ABSTAIN

3. To approve any proposal to adjourn or postpone the special meeting to a later date if necessary or appropriate, including an adjournment or postponement to solicit additional proxies if, at the special meeting, the number of Units present or represented by proxy and voting in favor of the approval of the amendment to the partnership agreement or the merger agreement is insufficient to approve the amendment of the Partnership agreement or the merger agreement, respectively.

[ ] FOR [ ] AGAINST [ ] ABSTAIN

In their discretion to vote upon such other matters that may properly come before the meeting.

X Please mark your Votes as in this Example.


Date:				Signature(s)

Contact phone number and address for payment of merger consideration:*


*		In the event that the amendment to the partnership agreement and the merger are approved and the merger is consummated, all payments of the cash merger consideration described in the accompanying proxy statement will be made by check, and will be mailed to each investor’s address designated for distributions, on file with PDC and the Partnership, unless another address is indicated above.


SUMMARY TERM SHEET			1
Special Meeting of Investors			1
Proposed Merger Transaction			1
Other Important Considerations			4
Questions and Answers About the Proposed Merger Transaction			6
SPECIAL FACTORS WITH RESPECT TO THE MERGER			13
General			13
Background of the Merger			13
PDC’s Reasons for the Merger			22
The Partnership’s Reasons for the Merger			23
Position of the Partnership Affiliates as to the Fairness of the Merger to the Unaffiliated Holders of Limited Partnership Interests			23
The Partnership’s Discussion of the Fairness of the Merger; Recommendation of the Special Committee on Behalf of the Partnership			26
Opinion of the Special Committee’s Financial Advisor			28
Regulatory Approvals			37
Alternatives to the Merger			37
Third-Party Offers			42
Effects of the Merger			42
Effect on Net Book Value and Net Earnings of PDC and Merger Sub			42
Conflicting Duties of PDC, Individually and as the General Partner			42
Financial Interests of Officers and Directors			43
Termination of Registration and Reporting Requirements			44
Material U.S. Federal Income Tax Consequences			44
Accounting Treatment			44
Sources of Funds			45
Payment of Expenses and Fees			45
RISK FACTORS			47
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			50
THE SPECIAL MEETING			51
Date, Time and Place			51
Purpose of the Special Meeting			51
Recommendation of the Special Committee			51
Record Date; Voting Rights And Proxies			51
Voting Your Limited Partnership Units			52
Solicitation of Proxies and Costs			52
Quorum			53
Investor Vote Required to Approve the Amendment to the Partnership Agreement and the Merger Agreement			53
Abstentions and Broker Non-Votes			53
Local Laws			53
PROPOSAL 1 — APPROVAL OF THE AMENDMENT TO THE PARTNERSHIP AGREEMENT			54
PROPOSAL 2 — APPROVAL OF THE MERGER AGREEMENT			55
METHOD OF DETERMINING MERGER VALUE AND AMOUNT OF CASH OFFERED			56


Components of Merger Value			56
Other Methods of Determining Merger Value			57
THE MERGER AGREEMENT			59
Structure; Effective Time			59
Representations and Warranties of PDC, the Merger Sub and the Partnership			59
Payment of Consideration for the Investor Limited Partnership Units			59
Conditions to Complete the Merger			59
Termination of the Merger and the Merger Agreement			60
Amending the Merger Agreement			61
Waiving Certain Merger Provisions			61
THIRD-PARTY OFFERS			61
DISTRIBUTION OF CASH PAYMENTS			61
RIGHTS OF DISSENTING INVESTORS			62
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			65
TRANSACTIONS AMONG THE PARTNERSHIP, PDC, THE MERGER SUB AND THEIR DIRECTORS AND OFFICERS			66
Certain Relationships and Related Transactions			66
Transactions in Limited Partnership Units			69
MANAGEMENT			70
RESERVE REPORT			73
SUMMARY FINANCIAL INFORMATION			74
PROPOSAL 3 — ADJOURNMENT OF THE SPECIAL MEETING			75
OTHER MATTERS			76
ADDITIONAL BUSINESS INFORMATION			76
Petroleum Development Corporation			76
DP 2004 Merger Sub, LLC			76
PDC 2002-D Limited Partnership			76
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			93
DELIVERY OF DOCUMENTS TO INVESTORS SHARING AN ADDRESS			109
WHERE YOU CAN FIND MORE INFORMATION			109
COMMONLY USED OIL AND GAS TERMS			110
APPENDIX A
Agreement and Plan of Merger			A-1
APPENDIX B
Opinion of the Special Committee’s Financial Advisor			B-1
APPENDIX C
West Virginia Business Corporation Act — Appraisal Rights			C-1
APPENDIX D
Reserve Report			D-1
APPENDIX E
Financial Statements			E-1
APPENDIX F
Partnership Agreement			F-1
APPENDIX G
Form of Amendment to Partnership Agreement			G-1


	By:	PETROLEUM DEVELOPMENT CORPORATION, its Managing General Partner


Condensed Balance Sheets (unaudited) — June 30, 2011 and December 31, 2010			E-3
Condensed Statements of Operations — For the Three and Six Month Periods Ended June 30, 2011 and 2010			E-4
Condensed Statements of Cash Flows — For the Three and Six Month Periods Ended June 30, 2011			E-5
Notes to Unaudited Condensed Financial Statements			E-6


Report of Independent Registered Public Accounting Firm			E-16
Balance Sheets — December 31, 2010 and 2009			E-17
Statements of Operations — For the Years Ended December 31, 2010 and 2009			E-18
Statements of Partners’ Equity — For the Years Ended December 31, 2010 and 2009			E-19
Statements of Cash Flows — For the Years Ended December 31, 2010 and 2009			E-20
Notes to Financial Statements			E-21
Supplemental Natural Gas, NGL and Crude Oil Information — Unaudited			E-38


MANAGING GENERAL PARTNER:		INITIAL LIMITED PARTNER:

Petroleum Development Corporation 103 East Main Street Bridgeport, West Virginia 26330		Steven R. Williams 103 East Main Street Inc. Bridgeport, West Virginia 26330

By:	/s/ Steven R. Williams Steven R. Williams President


NUMBER OF UNITS PURCHASED		ADDITIONAL GENERAL PARTNER(S):

		Name:
		(Print Name)

SUBSCRIPTION PRICE
		(Signature)

$		Address:



		By: Petroleum Development Corporation

		By:

		Its:
		Attorney-in-Fact


NUMBER OF UNITS PURCHASED		LIMITED PARTNER(S):

		Name:
		(Print Name)

SUBSCRIPTION PRICE
		(Signature)

$		Address:



		By: Petroleum Development Corporation

		By:

		Its:
		Attorney-in-Fact