UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

T þ ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, ~~2009~~2010

¨o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 000-51309

PDC 2005-A Limited Partnership

(Exact name of registrant as specified in its charter)

West Virginia		20-2088347
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1775 Sherman Street, Suite 3000, Denver, Colorado 80203

(Address of principal executive offices) (Zip code)

Registrant's telephone number, including area code (303) 860-5800

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act:

Title of Each Class

Limited Partnership Interests

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No Tþ

Indicate by check mark if registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No Tþ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. ~~Yes T No ¨~~

Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. Tþ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definition of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act:

Large accelerated filer ¨ Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company Tþ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No Tþ

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter:

There is no trading market in the Partnership’s securities. Therefore, there is no aggregate market value.

As of December 31, ~~2009~~2010, the Partnership had 1,996.87 units of limited partnership interest and no units of additional general partnership interest outstanding.

PDC 2005-A LIMITED PARTNERSHIP

~~INDEX~~2010 TOANNUAL REPORT ON FORM 10-K

		Page
PART I
	Special Note Regarding Forward-Looking Statements	1
Item 1	Business	2
Item 1A	Risk Factors	15
Item 1B	Unresolved Staff Comments	15
Item 2	Properties	15
Item 3	Legal Proceedings	15
Item 4	[Reserved]	15
PART II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	16
Item 6	Selected Financial Data	17
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	27
Item 8	Financial Statements and Supplementary Data	27
Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	28
Item 9A(T)	Controls and Procedures	28
Item 9B	Other Information	29
PART III
Item 10	Directors, Executive Officers and Corporate Governance	30
Item 11	Executive Compensation	34
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	34
Item 13	Certain Relationships and Related Transactions, and Director Independence	34
Item 14	Principal Accountant Fees and Services	36
PART IV
Item 15	Exhibits, Financial Statement Schedules	37
Signatures		38
Financial Statements		F-1

TABLE OF CONTENTS

Index

		Page
	PART I
Item 1	Business	3
Item 1A	Risk Factors	23
Item 1B	Unresolved Staff Comments	23
Item 2	Properties	23
Item 3	Legal Proceedings	23
Item 4	[Removed and Reserved]	23
	PART II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	24
Item 6	Selected Financial Data	26
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	40
Item 8	Financial Statements and Supplementary Data	40
Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	40
Item 9A	Controls and Procedures	40
Item 9B	Other Information	41

	PART III
Item 10	Directors, Executive Officers and Corporate Governance	42
Item 11	Executive Compensation	46
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	47
Item 13	Certain Relationships and Related Transactions, and Director Independence	47
Item 14	Principal Accountant Fees and Services	47

	PART IV
Item 15	Exhibits, Financial Statement Schedules	50

Signatures		53

Financial Statements		F-1

Table Of Contents

PART I

~~Special~~WHERE ~~Note~~YOU ~~Regarding~~CAN ~~Forward-Looking~~FIND ~~Statements~~MORE INFORMATION

~~This~~The Annual Report contains “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”) regarding PDC 2005-A Limited Partnership’s (the “Partnership’s” or the “Registrant’s”) ~~business,~~is ~~financial~~subject ~~condition~~to the reporting and ~~results~~information requirements of ~~operations. All~~the ~~statements~~Securities ~~other~~Exchange ~~than~~Act ~~statements~~ of ~~historical~~1934, ~~facts~~as ~~included~~amended, in and ~~incorporated~~is byas ~~reference~~a ~~into~~result ~~this~~obligated ~~report~~to ~~are~~file ~~forward-looking~~periodic ~~statements. Words such as “expects”~~reports, ~~“anticipates”,~~proxy ~~“intends”,~~statements ~~“plans”, “believes”, “seeks”, “estimates”~~ and ~~similar~~other ~~expressions~~information orwith ~~variations~~the ofSEC. The ~~such~~SEC ~~words~~maintains ~~are~~a ~~intended~~website tothat ~~identify~~contains ~~forward-looking~~the ~~statements~~annual, ~~herein~~quarterly, ~~which~~and ~~include~~current ~~statements~~reports, ofproxy ~~estimated natural gas~~ and ~~oil~~information ~~production~~statements, and ~~reserves,~~other ~~drilling~~information ~~plans,~~regarding ~~future~~the ~~cash flows~~Partnership, ~~anticipated~~which ~~liquidity,~~the ~~anticipated~~Partnership ~~capital~~electronically ~~expenditures~~files ~~and~~with the ~~Managing General Partner PDC’s strategies, plans and objectives~~SEC. ~~However,~~The ~~these~~address ~~are not the exclusive means~~ of ~~identifying~~that ~~forward-looking~~site ~~statements~~is ~~herein~~http://www.sec.gov. ~~Although~~The ~~forward-looking~~Central ~~statements~~Index ~~contained~~Key, inor ~~this~~CIK, ~~report~~for ~~reflect~~ the ~~Managing~~Partnership ~~General~~is ~~Partner's~~0001326539. You ~~good faith judgment, such statements~~ can ~~only~~read beand ~~based~~copy onany ~~facts~~materials ~~and~~the ~~factors~~Partnership ~~currently~~files ~~known~~with to the ~~Managing~~SEC ~~General~~at ~~Partner. Consequently,~~the ~~forward-looking~~SEC’s ~~statements~~Public ~~are~~Reference ~~inherently~~Room ~~subject~~at to100 ~~risks~~F ~~and~~Street, ~~uncertainties~~N.E., ~~including~~Room ~~risks and uncertainties incidental to the development~~1850, ~~production and marketing of natural gas and oil~~Washington, ~~and~~D.C. 20549. You ~~actual outcomes~~ may ~~differ~~obtain ~~materially~~information ~~from~~on the ~~results~~operation ~~and~~of ~~outcomes discussed in~~ the ~~forward-looking~~Public ~~statements.~~Reference ~~Important~~Room ~~factors~~by ~~that~~calling ~~could cause actual results to differ materially from~~ the ~~forward~~SEC ~~looking~~at ~~statements include, but are not limited to:~~1-800-SEC-0330.

·UNITS ~~changes~~OF ~~in production volumes, worldwide demand, and commodity prices for oil and natural gas;~~MEASUREMENT

·The ~~risks~~following ~~incident~~presents toa ~~the~~list ~~operation~~of units of ~~natural~~measurement ~~gas~~used ~~and~~throughout ~~oil~~the ~~wells;~~document.

·Bbl ~~future~~– ~~production~~One ~~and~~barrel ~~development~~of ~~costs;~~crude oil or NGL (Natural Gas Liquids) or 42 gallons of liquid volume.

Bcf – One billion cubic feet of natural gas volume.

Bcfe – One billion cubic feet of natural gas equivalent.

Btu – British thermal unit.

BBtu – One billion British thermal units.

MBbls – One thousand barrels of crude oil or NGLs.

Mcf – One thousand cubic feet of natural gas volume.

Mcfe – One thousand cubic feet of natural gas equivalent (six Mcf of natural gas equals one Bbl of crude oil or NGL).

MMBtu – One million British thermal units.

MMcf – One million cubic feet of natural gas volume.

MMcfe – One million cubic feet of natural gas equivalent.

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Table Of Contents

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report contains “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”) regarding PDC 2005-A Limited Partnership’s business, financial condition and results of operations. Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, is the Managing General Partner of the Partnership.

All statements other than statements of historical facts included in and incorporated by reference into this report are forward-looking statements. Words such as “expects”, “anticipates”, “intends”, “plans”, “believes”, “seeks”, “estimates” and similar expressions or variations of such words are intended to identify forward-looking statements herein, which include statements of estimated natural gas, natural gas liquid(s) or “NGL(s)”, and crude oil production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner’s strategies, plans and objectives. However, these are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect the Managing General Partner's good faith judgment, such statements can only be based on facts and factors currently known to the Managing General Partner. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including risks and uncertainties incidental to the development, production and marketing of natural gas, NGLs and crude oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Important factors that could cause actual results to differ materially from the forward looking statements include, but are not limited to:

changes in production volumes, worldwide demand, and commodity prices for natural gas, NGLs and crude oil;

changes in estimates of proved reserves;

declines in the values of the Partnership’s natural gas and crude oil properties resulting in impairments;

the timing and extent of the Partnership’s success in further developing and producing reserves;

the Managing General Partner’s ability to acquire drilling rig services, supplies and services at reasonable prices;

risks incident to the refracturing and operation of natural gas and crude oil wells;

future production and refracturing costs;

the availability of Partnership future cash flows for investor distributions or funding of refracturing activities;

the availability of sufficient pipeline and other transportation facilities to carry Partnership production and the impact of these facilities on price;

· the effect of existing and future laws, governmental regulations and the political and economic climate of the United States of America, (“or U.S.”);

· ~~the~~changes ~~effect~~in ofenvironmental ~~natural~~laws ~~gas~~and the regulation and ~~oil~~enforcement ~~derivatives~~related ~~activities~~to those laws;

the identification of and severity of environmental events and governmental responses to the events;

the effect of natural gas and crude oil derivatives activities;

the availability of funding for the consideration payable by PDC and its wholly-owned subsidiary to consummate the prospective mergers of the 2005 partnerships and the timing of consummating these mergers, if at all;

conditions in the capital markets; and

losses possible from pending or future litigation.

Further, the Partnership urges the reader to carefully review and consider the ~~cautionary~~disclosures ~~statements~~ made in this report and the Partnership’s other filings with the SEC ~~and public disclosures~~. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. The Partnership undertakes no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events.

- 1 2-

~~Index~~Table Of Contents

~~Item~~ITEM 1. ~~Business~~ BUSINESS

General Information

The Partnership is a ~~publically~~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 2005 with cash contributed by limited and additional general partners (collectively, the “Investor Partners”), ~~who~~and the Managing General Partner. The Investor Partners own 80% of the Partnership’s capital, or equity interests~~, and~~ . PDC, the Managing General Partner, a Nevada Corporation, ~~who~~ owns the remaining 20% of the Partnership’s capital, or equity interest. Upon funding, the Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner that governs the drilling and operational aspects of the Partnership. In accordance with the Limited Partnership Agreement (the “Agreement”), general partnership interests were converted to limited partnership units at the completion of the Partnership’s drilling activities. The Partnership ~~utilized~~expended substantially all of the capital raised in the offering for the initial drilling and completion of the Partnership’s wells.

InThe ~~accordance~~Managing ~~with~~General ~~the~~Partner ~~Limited~~may ~~Partnership~~repurchase ~~Agreement~~Investor (Partner units, under certain circumstances provided by the “Agreement”), ~~general~~upon ~~partnership~~request ~~interests~~of ~~were~~an ~~converted~~individual toinvestor partner. For more information about the Managing General Partner’s limited ~~partnership~~partner ~~units~~unit atrepurchase program as well as the ~~completion~~current number of Investor Partners as of the ~~Partnership~~date of filing, see Item 5, Market for Registrant’s ~~drilling~~Common ~~activities~~Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. AFor ~~limited~~information ~~partner~~concerning the Managing General Partner’s ~~obligation~~ownership tointerests in the Partnership ~~under~~as ~~West~~of ~~Virginia~~the ~~law~~date isof ~~limited~~filing, tosee ~~his~~Item or12, ~~her~~Security ~~capital~~Ownership ~~contribution~~of Certain Beneficial Owners and Management and Related Stockholder Matters.

The ~~following~~Partnership ~~table~~expects ~~presents~~continuing operations of its natural gas and crude oil properties until such time the Partnership’s ~~formation~~wells are depleted or becomes uneconomical to produce, at which time that well may be sold or plugged, reclaimed and ~~organizational~~abandoned. The ~~information~~Partnership’s maximum term of existence extends through December 31, 2055, unless dissolved by certain conditions stipulated within the ~~completion~~Agreement which are unlikely to occur at this time, or by written consent of the ~~drilling~~Investor ~~phase~~Partners onowning ~~March~~a ~~20,~~majority ~~2006:~~of outstanding units at that time.

				Number of Partner Units
PDC 2005-A Limited Partnership Information	Date	Number of Partners		Additional General Partner Units			Limited Partner Units		Equity Percentage			Amount (millions)
West Virginia Limited Partnership Formation	November 30, 2004
Limited Partnership Termination Date	December 31, 2055
Public Sale of Securities and Funding	February 9, 2005
Investor Partners (1) Unit Cost: $20,000			1,523		1,872.08			124.79		80.00	%	$	39.9
PDC, Managing General Partner										20.00	%		8.8
Total funding													48.7
Syndication costs paid to third-party brokers													(4.0	)
Management Fee Paid to PDC													(0.6	)
Net funding available for drilling activities										100.00	%	$	44.1
Conversion of additional General Partners to Limited Partners	March 20, 2006				(1,872.08	)		1,872.08
Limited Partnership Units after Conversion					-			1,996.87

(1) The Managing General Partner repurchases 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 as well as the current number of Investor Partners as of the date of filing, see Item 5, Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. For information concerning the Managing General Partner’s ownership interests in the Partnership as of the date of filing, see Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The Partnership expects continuing operations of its oil and natural gas properties until such time that a well is depleted or becomes uneconomical to produce, at which time that well will be plugged and abandoned. The Partnership’s maximum term of existence extends through December 31, 2055, 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.

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.

Recent Developments

PDC Sponsored Drilling Program Acquisition Plan

PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue, beginning in the fall of 2010 and extending through the next three years, the acquisition of the limited partnership units (the “Acquisition Plan”) held by Investor Partners of that partnership other than PDC or its affiliates (“non-affiliated Investor Partners”), in the limited partnerships that PDC has sponsored, including this Partnership. For additional information regarding PDC’s intention to pursue acquisitions of PDC sponsored partnerships, refer to the disclosure included in Items 2.02, 7.01 and/or 8.01 of PDC’s Forms 8-K dated March 4, 2010, June 9, 2010, July 15, 2010 and November 17, 2010. However, such information shall not, by reason of this reference, be deemed to be incorporated by reference in, or otherwise be deemed to be part of, this report. Under the Acquisition Plan, any existing or future merger offer will be subject to the terms and conditions of the related merger agreement, and such agreement does or will likely contemplate the partnership being merged with and into a wholly-owned subsidiary of PDC. Each such merger will also be subject to, among other things, PDC having sufficient available capital and the approval by a majority of the limited partnerships units held by the non-affiliated Investor Partners of each respective limited partnership. Consummation of any proposed merger of a PDC sponsored limited partnership under the Acquisition Plan will likely result in the termination of the existence of that partnership and the right of non-affiliated Investor Partners to receive a cash payment for their limited partnership units in that partnership.

The feasibility and timing of any future purchase offer by PDC to any additional partnership depends on that partnership’s suitability in meeting a set of criteria that includes, but is not limited to, the following: age and productive-life stage characteristics of the partnership’s well inventory; favorability of economics for Wattenberg Field well refracturing; and SEC reporting compliance status and timing associated with gaining all necessary regulatory approvals required for a merger and repurchase offer. There is no assurance that any merger and acquisition will occur, as a result of PDC’s proposed repurchase offers to the 2005 partnerships (as defined below), including this Partnership, or any potential proposed repurchase offer to any other of PDC’s various public limited partnerships, should they occur.

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Table Of Contents

During 2010, PDC acquired four affiliated partnerships: PDC 2004-A Limited Partnership, PDC 2004-B Limited Partnership, PDC 2004-C Limited Partnership and PDC 2004-D Limited Partnership. PDC purchased these partnerships for the aggregate amount of $34.8 million. In November 2010, PDC and DP 2004 Merger Sub, LLC, a wholly-owned subsidiary of PDC (“DP Merger Sub”), entered into separate merger agreements with this Partnership, PDC 2005-B Limited Partnership and Rockies Region Private Limited Partnership (collectively, the “2005 partnerships”).

Pursuant to the Partnership’s merger agreement with PDC (the “Merger Agreement”), if the merger is approved by the holders of a 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 and non-affiliated Investor Partners will have the right to receive a cash payment for their limited partnership units. 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 Partnership will no longer be required to file reports with the SEC, and the non-affiliated Investor Partners will no longer participate in the Partnership’s future earnings or growth.

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 Board, on behalf of PDC individually, and the Special Committee, on behalf of PDC in its capacity as the Partnership’s Managing General Partner, have determined that the merger is advisable and in the best interests of PDC and the Partnership, respectively, and reasonably believe that the merger is fair to PDC and the non-affiliated Investor Partners in the Partnership, respectively.

Each member of the Special Committee, on behalf of PDC in its capacity as the Managing General Partner of the Partnership, has relied upon his own business judgment and analysis based on a variety of factors in addition to the financial analysis of an outside financial advisor with respect to the substantive fairness to the non-affiliated Investor Partners’ interests, from a financial point of view, of the consideration to be received by the non-affiliated Investor Partners pursuant to the Merger Agreement. Also, the Special Committee retained its own legal counsel to advise it regarding the terms of the proposed merger.

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 April 30, 2011; provided that if the SEC’s proxy disclosure review process has not yet been completed after good faith effort by PDC, such date will be extended until August 31, 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;

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Table Of Contents

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 the PDC or the Partnership, respectively, or materially and adversely affects the transactions contemplated by the Merger Agreement.

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.

In early February 2011, definitive proxy statements were mailed to non-affiliated Investor 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.

The per unit merger value offered to non-affiliated Investor Partners under the Merger Agreement in exchange for their limited partnership units in the Partnership was based on an effective transaction date of January 1, 2011.

PDC has re-evaluated the merger consideration agreed to in the Merger Agreement and has proposed to offer supplemental merger consideration to the non-affiliated Investor Partners in addition to the merger consideration described above. On March 25, 2011, the special meeting of non-affiliated Investor Partners of the Partnership was adjourned until May 27, 2011. PDC expects to send non-affiliated investor partners a proxy supplement that provides information relating to the increased merger consideration and also includes year-end financial statements and the Partnership's 2010 year-end reserve report. Although there is no assurance of the likelihood or timing of the completion of the SEC proxy disclosure review process or whether the Partnership will obtain the necessary approvals from non-affiliated Investors Partners, PDC would expect to mail such proxy supplements to the non-affiliated Investors Partners in late April or early May.

If the merger is not completed, the anticipated non-affiliated Investor Partner merger benefits that include unit liquidity and elimination of Schedule K-1 tax reports in the Partnership will not be realized and the Partnership will continue the existing business plan to optimally develop and cost-effectively operate the Partnership’s natural gas and oil reserves. This plan encompasses the implementation of the Well Refracturing Plan, more fully outlined below. The information presented in this Annual Report on Form 10-K for the year ended December 31, 2010 does not give effect to the proposed Merger Agreement.

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Table Of Contents

Business Strategy

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

-The 2Partnership’s -business plan going forward, including the Well Refracturing 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 as outlined in the Partnership’s cash distribution policy discussed in Item 5, Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. Partnership cash distributions may be withheld pursuant to the Well Refracturing Plan.

Index

Development

The Partnership’s Denver-Julesburg (“DJ”) Basin wells are situated in the Wattenberg Field, located north and east of Denver. The Codell formation, from which natural gas and oil is produced, is the primary producing zone for most of the Partnership’s 36 wells developed in the Wattenberg Field. The Partnership’s Piceance Basin wells are situated in the Grand Valley Field, located near the western border of Colorado. The Mesa Verde formation, where natural gas is the predominant hydrocarbon produced, is the primary producing zone for the Partnership’s 13 Grand Valley Field wells. The typical well production profile for wells in both the Wattenberg and Grand Valley fields displays an initial high production rate and relatively rapid decline, followed by years of relatively shallow decline.

Well recompletions in the Codell formation of Wattenberg Field wells, which may provide for additional reserve development and production, generally occur five to ten years after initial well drilling so that well resources are optimally utilized. These well recompletions would be expected to occur based on a favorable general economic environment and commodity price structure. The Managing General Partner has the authority to determine whether to recomplete the individual wells and to determine the timing of any recompletions. The timing of the recompletions can be affected by the desire to optimize the economic return by recompleting the wells when commodity prices are at levels to obtain the highest rate of return to the Partnership. The number and timing of the Partnership’s well recompletions will be subject to Partnership’s cash availability since borrowing is not permitted. The Managing General Partner may retain Partnership distributable cash flows, if needed, so that Partnership operations may fully develop the Partnership's wells; but if full development of the Partnership's wells proves commercially unsuccessful, an individual investor partner might anticipate a reduction in cash distributions.

A recompletion consists of a second fracture treatment in the same formation originally fractured in the initial completion. PDC and other producers have found that the recompletions generally increase the production rate and recoverable reserves of the wells. On average, the production resulting from PDC's Codell recompletions has been above the modeled economics; however, all recompletions have not been economically successful and future recompletions may not be economically successful. The cost of recompleting a well producing from the Codell formation is generally one third of the cost of a new well. If the recompletion work is performed, PDC will charge the Partnership for the direct costs of recompletions, and the Investor Partners and the Managing General Partner will each pay their proportionate share of costs based on the operating costs sharing ratios of the Partnership from funds retained by the Managing General Partner from distributable cash flows.

The Managing General Partner has developed a plan to initiate recompletion activities during 2011. This plan includes notifying investor partners that funds to begin these recompletions will be withheld from future distributable cash flows of the Partnership resulting from both current production and any increased production due to recompletion activities. The funds retained necessary for the Partnership to pay for recompletion costs will materially reduce, up to 100%, distributable cash flows for a period of time not to exceed five years. If any or all of the Partnership’s Wattenberg wells are not recompleted, the Partnership will experience a reduction in proved reserves currently assigned to these wells. Both the number of recompletions and the timing of recompletions will be based on the availability of cash withheld from distributions. The Managing General Partner believes that, based on projected recompletion costs and projected cash withholding, all partnership recompletions can be completed. As the optimal period approaches, the Managing General Partner will re-evaluate the feasibility of commencing those recompletions based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the recompletion.

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Index

Drilling and Other Development Activities

The Partnership’s properties (the “Properties”) consist of a working interest for the well bore in each well drilled by the Partnership. The Partnership drilled 49 development wells (44.4 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 2006 when the last of the Partnership’s wells were connected to sales and gathering lines. No exploratory drilling activity was conducted on behalf of the Partnership. The 49 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 utilized. In accordance with the D&O Agreement, the Partnership paid its proportionate share of the cost of drilling and completing each well as follows:

· The leasehold cost of the prospect;

· The intangible well costs for each well completed and placed in production; and

· The tangible costs of drilling and completing the partnership wells and of gathering pipelines necessary to connect the well to the nearest appropriate sales point or delivery point.

The Partnership’s business plan going forward is to produce and sell the oil and gas from the Partnership’s wells, and to make distributions to the partners as outlined in the Partnership’s cash distribution policy, discussed in Item 5, Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Title to Properties

The Partnership's leases are direct interests in producing acreage. In accordance with the D&O Agreement, the Managing General Partner 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. The Managing General Partner does not believe that any additional burdens, liens or encumbrances customary to the industry, if any, will materially interfere with the commercial use of the properties. Provisions of the Agreement generally relieve PDC from any error in judgment with respect to the waiver of title defects.

Natural Gas and Oil Reserves

The Partnership’s gas and oil 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. The Managing General Partner has a comprehensive process that governs the determination and reporting of the Partnership’s proved reserves. As part of the Managing General Partner’s internal control process, the Partnership’s reserves are reviewed annually by an internal team composed of 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 2009 and 2008 natural gas and oil 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 the Managing General Partner with respect to ownership interests, natural gas and oil production, 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 the Managing General Partner’s engineers. A final comparison of data was performed to assure that the reserve estimates were complete and reasonable. The final independent petroleum engineer's estimated reserve report was reviewed and approved by the Managing General Partner’s engineering staff and management.

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Index

The professional qualifications of the Managing General Partner’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 Managing General Partner 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 in January 2009, Modernization of Oil and Gas Reporting.

Proved reserves are those quantities of oil and natural 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. These reserve quantities should be producible prior to the operating contract term’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 and 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.

The table below presents information as of December 31, 2009, regarding the Partnership’s proved reserves by production field, as estimated by Ryder Scott. Reserves cannot be measured exactly, because reserve estimates involve judgment. The estimates are 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 represent the reserves attributable to the future recompletions of the Codell formation in the Wattenberg Field wells. For additional information regarding the Partnership’s natural gas and oil reserves see Supplemental Oil and Gas Information – Unaudited, Net Proved Natural Gas and Oil Reserves accompanying the financial statements included in this report.

	As of December 31, 2009
					Natural Gas
	Oil		Natural Gas		Equivalent
	(MBbl)		(MMcf)		(MMcfe)		Percent
Proved developed
Piceance Basin: Grand Valley Field		14		7,382		7,466		88	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		115		357		1,047		12	%
Total proved developed		129		7,739		8,513		100	%
Proved undeveloped
Piceance Basin: Grand Valley Field		-		-		-		0	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		304		1,237		3,061		100	%
Total proved undeveloped		304		1,237		3,061		100	%
Proved reserves
Piceance Basin: Grand Valley Field		14		7,382		7,466		65	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		419		1,594		4,108		35	%
Total proved reserves		433		8,976		11,574		100	%

In 2009, the SEC published its final rule regarding the modernization of oil and gas reporting, which changed the valuation price of in-ground natural gas and oil resources, used to determine economically producible natural gas and oil reserve quantities, from a year-end single-day pricing method to a method which applies the 12-month average of the first-day-of-the-month price during each month of 2009. 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.

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Index

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 ~~complete~~completed, and production operations are currently being conducted with regard to each of the Partnership’s productive wells.

PDC, ~~through~~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 ~~services~~ 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 ~~which~~until ~~are~~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 ~~winter~~ weather conditions and time periods reserved by leasehold restrictions ~~designed to protect wildlife habitat~~ can exist and limit operational capabilities for as long as six months. ~~These~~Operational ~~factors may adversely affect some Partnership production operations. In addition to cold weather, operational~~ constraint challenges such as surface equipment freezing can limit production volumes. Increased competition ~~and higher costs during milder weather and habitat protection periods~~ for oil field equipment, services, supplies and qualified personnel ~~can~~and wildlife habitat protection periods may also adversely affect profitability and reduce cash distributions to the Investor Partners.

~~The~~Areas ~~following table presents the Partnership’s productive wells by operating field as~~ of ~~December 31, 2009. Productive wells consist of producing wells and wells capable of producing oil and natural gas in commercial quantities.~~Operations

	Producing Wells
	Gas
Location	Gross		Net
State of Colorado
Piceance Basin: Grand Valley Field		13.0		10.2
Denver-Julesburg (DJ) Basin: Wattenberg Field(1)		35.0		33.3
Total Colorado		48.0		43.5
Total Productive Wells(1)		48.0		43.5

(1) Not included in the producing well statistics above, is one Wattenberg Field well (0.9 net) temporarily shut-in at December 31, 2009 due to operational issues.

The Partnership’s operating areas are profiled as follows:

DJWattenberg ~~Basin~~Field, ~~Wattenberg~~DJ ~~Field~~Basin, Weld County, Colorado. Located north and east of Denver, Colorado, the Partnership’s wells in this field ~~have~~exhibit ~~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 ~~shallow~~lower rates of decline and production levels. Although natural gas is the primary hydrocarbon produced, ~~many~~ wells also produce NGLs and/or crude oil. ~~Development~~Of ~~wells~~the inPartnership’s ~~this~~36 ~~area~~wells ~~are~~drilled ~~generally 7,000 to 8,000 feet~~ in ~~depth~~the ~~and~~Wattenberg ~~their~~Field ~~primary~~that ~~producing~~were ~~zone~~completed isto the Codell formation, ~~with~~three ~~some~~ wells were also completed in the shallower Niobrara 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 6Valley Field, Piceance Basin, Garfield County, Colorado. Located near the western border of Colorado, the Partnership’s 13 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.

~~Index~~-6-

~~Piceance~~Table ~~Basin,~~Of Grand Valley Field, Garfield County, Colorado. Located near the western border of Colorado, the Partnership’s wells in this field have also exhibited production histories typical for wells located in this field with an initial high production rate and relatively rapid decline, followed by years of relatively shallow decline. These wells generally produce natural gas along with small quantities of oil. The majority of development wells drilled in the area are 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.Contents

~~Sale~~Title ~~of Production. In accordance with the D&O Agreement, PDC markets the natural gas produced from the Partnership’s wells primarily~~ to commercial end users, interstate or intrastate pipelines or local utilities on a competitive basis, under the available terms and prices, generally under contracts with indexed monthly pricing provisions. The Managing General Partner believes these contract pricing provisions are customary for the industry. The sales price for natural gas may include revenue from the recovery of propane and butane in the gas stream, as well as a premium for the typical high-energy content of the natural gas. The Partnership’s Wattenberg Field and, to a lesser extent, the Grand Valley Field wells also produce oil in addition to natural gas. The Managing General Partner is currently able to sell, at or near the Partnership’s wells, all of the Partnership’s oil production under a purchase contract with a regional petroleum refiner containing monthly pricing provisions. The Partnership does not refine any of its oil production.Properties

-The 7Partnership's -leases are direct interests in producing acreage. In accordance with the D&O Agreement, the Managing General Partner 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. The Managing General Partner 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 Agreement generally relieve PDC from errors in judgment with respect to the waiver of title defects.

~~Index~~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 49 development wells (44.4 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 ~~Gas~~concluded ~~Production,~~in ~~Unit~~August ~~Prices~~2006 when the last of the Partnership’s wells were connected to sales and ~~Costs~~gathering lines. No exploratory drilling activity was conducted on behalf of the Partnership. The 49 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 ~~information regarding~~ the Partnership’s ~~operations~~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.

	Year Ended December 31,
	Producing Gas Wells
	2009		2008
	2010				2009
Production (1)
Location	Gross		Net		Gross		Net
Natural gas (Mcf)
State of Colorado
Piceance Basin: Grand Valley Field		~~712,349~~13.0		~~740,028~~10.2		13.0		10.2
Denver-Julesberg (DJ) Basin: Wattenberg Field		55,380		64,503
Denver-Julesburg (DJ) Basin: Wattenberg Field		36.0		34.2		35.0		33.3
Total Natural Gas		767,729		804,531
Total Productive Wells (1)		49.0		44.4		48.0		43.5
Oil (Bbls)
Piceance Basin: Grand Valley Field		1,725		2,074
Denver-Julesberg (DJ) Basin: Wattenberg Field		20,752		23,279
Total Oil		22,477		25,353
Natural gas equivalent (Mcfe)
Piceance Basin: Grand Valley Field		722,699		752,472
Denver-Julesberg (DJ) Basin: Wattenberg Field		179,892		204,177
Total natural gas equivalent		902,591		956,649
Natural Gas and Oil Sales
Natural gas sales
Piceance Basin: Grand Valley Field	$	1,857,147	$	4,625,643
Denver-Julesberg (DJ) Basin: Wattenberg Field		226,151		532,327
Total natural gas sales		2,083,298		5,157,970
Oil sales
Piceance Basin: Grand Valley Field	$	68,643	$	184,560
Denver-Julesberg (DJ) Basin: Wattenberg Field		1,116,197		2,068,007
Total oil sales		1,184,840		2,252,567
Natural gas and oil sales
Piceance Basin: Grand Valley Field	$	1,925,790	$	4,810,203
Denver-Julesberg (DJ) Basin: Wattenberg Field		1,342,348		2,600,334
Total natural gas and oil sales	$	3,268,138	$	7,410,537
Average Sales Price (excluding realized gain (loss) on derivatives)
Natural gas (per Mcf)
Piceance Basin: Grand Valley Field	$	2.61	$	6.25
Denver-Julesberg (DJ) Basin: Wattenberg Field		4.08		8.25
Average sales price natural gas, all fields		2.71		6.41
Oil (per Bbl)
Piceance Basin: Grand Valley Field	$	39.79	$	88.99
Denver-Julesberg (DJ) Basin: Wattenberg Field		53.79		88.84
Average sales price oil, all fields		52.71		88.85
Natural gas equivalent (per Mcfe)
Piceance Basin: Grand Valley Field	$	2.66	$	6.39
Denver-Julesberg (DJ) Basin: Wattenberg Field		7.46		12.74
Average sales price natural gas equivalents, all fields		3.62		7.75
Average Production (Lifting) Cost (2) (per Mcfe)
Piceance Basin: Grand Valley Field	$	1.24	$	1.10
Denver-Julesberg (DJ) Basin: Wattenberg Field		2.82		1.90
Average production cost, all fields		1.56		1.27

-(1) 8Not -included in the productive well statistics above is one Wattenberg Field Partnership well (0.9 net) temporarily not in production at December 31, 2009 due to operational issues.

~~Index~~Well Refracturing Plan. The Managing General Partner has prepared a plan for the Partnership’s Wattenberg Field wells which may provide for additional reserve development and natural gas, NGLs and crude oil production (the “Well Refracturing Plan”). The Well Refracturing Plan consists of the Partnership’s refracturing of wells currently producing in the Codell formation. Under the Well Refracturing Plan, the Partnership plans to initiate refracturing activities during 2012. Refracturing, or “refracing,” activities consist of a second hydraulic fracturing treatment in a current production zone, all within an existing well bore.

~~(1)~~Refracturing ~~Production~~of asWattenberg ~~shown~~Field inwells, 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 refracturing would be expected to occur based on a favorable general economic environment and commodity price structure. The Managing General Partner has the ~~table~~authority isto ~~determined~~determine bywhether ~~multiplying~~to refrac the ~~gross~~individual ~~production~~wells ~~volume~~and to determine the timing of ~~properties~~any inrefracturing ~~which~~activity. The timing of the ~~Partnership~~refracturing ~~has~~can anbe ~~interest~~affected by the ~~percentage~~desire to optimize the economic return by refracturing the wells when commodity prices are at levels to obtain the highest rate of return to the ~~leasehold~~Partnership. On oraverage, ~~other~~the ~~property~~production ~~interest~~resulting from PDC's Codell refracturings have been at modeled economics; however, all refracturings have not been economically successful and similar future refracturing activities may not be economically successful. If the refracturing work is performed, PDC will charge the Partnership ~~owns~~for the direct costs of refracturing, and the Investor Partners and the Managing General Partner will each pay their proportionate share of costs based on the ownership sharing ratios of the Partnership from funds retained by the Managing General Partner from distributable cash flows.

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Table Of Contents

During the fourth quarter 2010, the Managing General Partner began withholding funds from several of the PDC sponsored partnerships, on a pro-rata basis, allocated to the Managing General Partner and Investor Partners based on their proportional ownership interest, from distributable cash flows of the Partnership resulting from current production. The funds retained are necessary for the Partnership to pay for refracturing costs and will materially reduce, up to 100%, distributable cash flows of the Partnership for a period of time not to exceed five years. If any or all of the Partnership’s Wattenberg wells are not refractured, the Partnership will experience a reduction in proved reserves currently assigned to these wells. Both the number and timing of the refracturing activities will be based on the availability of cash withheld from Partnership distributions. The Managing General Partner believes that, based on projected refracturing costs and projected cash withholding, all scheduled Partnership refracturing activity will be completed within a five year period.

Current estimated costs for these well refracturings are between $175,000 and $240,000 per activity. As of December 31, 2010, this Partnership has scheduled to complete 35 refracturing opportunities. This increase from 33 potential refracturing opportunities as of December 31, 2009 is due to an increase in estimated future distributable cash flows based on current pricing and well economics. Total withholding for these activities from the Partnership’s distributable cash flows is estimated to be between $6.1 million and $8.4 million. The Managing General Partner will continually evaluate the timing of commencing these refracturing 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 December 31, 2010, $60,000 has been withheld from the Partnership distributions pursuant to the Well Refracturing Plan. Cumulatively, $100,000 has been withheld from Partnership distributions through February 28, 2011.

Implementation of the Well Refracturing Plan would reduce or eliminate Partnership distributions to the Managing General Partner and Investor Partners 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 the Managing General Partner and Investor Partners could have taxable income from the Partnership without any corresponding distributions in future years. Non-affiliated Investor Partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the Well Refracturing Plan. The above discussion is not intended as a substitute for careful tax planning, and non-affiliated Investor Partners should depend upon the advice of their own tax advisors concerning the effects of the Well Refracturing 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.

The Managing General Partner established a comprehensive process that governs the determination and reporting of the Partnership’s proved reserves. As part of the Managing General Partner’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 the Managing General Partner 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.

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Table Of Contents

The independent petroleum engineer prepared an estimate of the Partnership’s reserves in conjunction with an ongoing review by the Managing General Partner’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 the Managing General Partner deems appropriate. The final independent petroleum engineer's estimated reserve report was reviewed and approved by the Managing General Partner’s engineering staff and management.

The professional qualifications of the Managing General Partner’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 Managing General Partner 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 refracturing.

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Table Of Contents

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 Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Reporting on NGLs in 2010 for additional information.

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. Neither the estimated future net cash flows nor the standardized measure is intended to represent the current market value of our proved reserves. The Partnership’s estimated proved undeveloped reserves consist entirely of reserves attributable to the Wattenberg Field’s future refracturing of 35 of the Partnership’s Codell formation wells. (See Item 1, Business−Operations, Drilling and Other Activities-Well Refracturing Plan on page 6) For additional information regarding the Partnership’s reserves see the Net Proved Reserves section of the Supplemental Information provided with the financial statements included in this report. There were no proved undeveloped reserves that were developed in 2010.

	December 31,
	2010
Proved Reserves
Natural gas (MMcf)		7,856
Crude Oil and Condensate (MBbl)		448
NGLs (MBbl)		98
Total proved reserves (MMcfe)		11,132
Proved developed reserves (MMcfe)		7,855
Estimated future net cash flows (in thousands)(1)	$	32,192
Standardized measure (in thousands) (1)(2)	$	16,883

(1)

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.

(2)

The standardized measure of discounted future net cash flow represents the present value of estimated future net cash flows discounted at a rate of 10% per annum to reflect timing of future cash flows.

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Table Of Contents

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

	As of December 31, 2010
	Natural Gas (MMcf)		NGLs (MBbl)		Crude Oil and Condensate (MBbl)		Natural Gas Equivalent (MMcfe)		Percent
Proved developed
Piceance Basin: Grand Valley Field		6,612		-		11		6,678		85	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		301		24		122		1,177		15	%
Total proved developed		6,913		24		133		7,855		100	%

Proved undeveloped
Piceance Basin: Grand Valley Field		-		-		-		-		0	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		943		74		315		3,277		100	%
Total proved undeveloped		943		74		315		3,277		100	%

Proved reserves
Piceance Basin: Grand Valley Field		6,612		-		11		6,678		60	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		1,244		98		437		4,454		40	%
Total proved reserves		7,856		98		448		11,132		100	%

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Table Of Contents

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. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Reporting on NGLs in 2010 for additional details.

	Year Ended December 31,
	2010		2009
Production(1)

Natural gas (Mcf)
Piceance Basin: Grand Valley Field		631,216		712,349
Denver-Julesberg (DJ) Basin: Wattenberg Field		44,477		55,380
Total Natural Gas		675,693		767,729

Crude Oil (Bbl)
Piceance Basin: Grand Valley Field		1,119		1,725
Denver-Julesberg (DJ) Basin: Wattenberg Field		21,387		20,752
Total Crude Oil		22,506		22,477

NGLs (Bbl)
Denver-Julesberg (DJ) Basin: Wattenberg Field		3,551		-

Natural gas equivalent (Mcfe)
Piceance Basin: Grand Valley Field		637,930		722,699
Denver-Julesberg (DJ) Basin: Wattenberg Field		194,105		179,892
Total natural gas equivalent		832,035		902,591

Natural Gas, NGLs and Crude Oil Sales

Natural gas sales
Piceance Basin: Grand Valley Field	$	2,120,815	$	1,857,147
Denver-Julesberg (DJ) Basin: Wattenberg Field		161,053		226,151
Total natural gas sales		2,281,868		2,083,298

Crude oil sales
Piceance Basin: Grand Valley Field	$	66,712	$	68,643
Denver-Julesberg (DJ) Basin: Wattenberg Field		1,577,122		1,116,197
Total crude oil sales		1,643,834		1,184,840

NGLs sales
Denver-Julesberg (DJ) Basin: Wattenberg Field	$	127,763	$	-

Natural gas, NGLs and crude oil sales
Piceance Basin: Grand Valley Field	$	2,187,527	$	1,925,790
Denver-Julesberg (DJ) Basin: Wattenberg Field		1,865,938		1,342,348
Total natural gas, NGLs and crude oil sales	$	4,053,465	$	3,268,138

Average Sales Price (excluding realized gain on derivatives)

Natural gas (per Mcf)
Piceance Basin: Grand Valley Field	$	3.36	$	2.61
Denver-Julesberg (DJ) Basin: Wattenberg Field		3.62		4.08
Average sales price natural gas, both fields		3.38		2.71

Crude Oil (per Bbl)
Piceance Basin: Grand Valley Field	$	59.62	$	39.79
Denver-Julesberg (DJ) Basin: Wattenberg Field		73.74		53.79
Average sales price crude oil, both fields		73.04		52.71

NGLs (per Bbl)
Denver-Julesberg (DJ) Basin: Wattenberg Field	$	35.98	$	-

Natural gas equivalent (per Mcfe)
Piceance Basin: Grand Valley Field	$	3.43	$	2.66
Denver-Julesberg (DJ) Basin: Wattenberg Field		9.61		7.46
Average sales price natural gas equivalents, both fields		4.87		3.62

Average Production (Lifting) Cost (2) (per Mcfe)

Piceance Basin: Grand Valley Field	$	1.14	$	1.24
Denver-Julesberg (DJ) Basin: Wattenberg Field		2.31		2.82
Average production cost, both fields		1.41		1.56

(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.

~~Definitions used throughout Item 1,Business:~~-12-

·Table ~~Bbl~~Of ~~– One barrel or 42 U.S. gallons liquid volume~~Contents

·For ~~MBbl~~more –information ~~One~~concerning ~~thousand~~the ~~barrels~~Partnership’s production volumes and costs, which include severance and ad valorem taxes as reflected in the Partnership’s statements of operations accompanying this report, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in this report.

·Natural ~~Mcf~~Gas, –NGLs ~~One~~and ~~thousand~~Crude ~~cubic~~Oil ~~feet~~Sales

·In ~~Mcfe~~accordance –with ~~One~~the ~~thousand~~D&O ~~cubic~~Agreement, ~~feet~~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. The Managing General Partner 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, ~~equivalents~~NGLs and crude oil because these services are covered by the monthly well operating charge. This monthly charge is more fully described in the following Item 1, Business−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 ~~ratio~~well delivers to a gathering or transmission line, quality of 6natural ~~Mcf~~gas ~~for~~and ~~each~~prevailing ~~barrel~~supply and demand conditions, so that the price of ~~oil~~the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, ~~which~~the ~~reflect~~Partnership’s revenues from the ~~relative~~sale ~~energy~~of ~~content~~natural gas, holding production volume constant, increase as market prices increase and decrease as market prices decline. The Managing General Partner believes that the pricing provisions of the Partnership’s natural gas contracts are customary in the industry. The Managing General Partner also enters into financial derivatives in order to reduce the impact of possible price instability regarding the physical sales market. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation: Results of Operations – Commodity Price Risk Management, Net and Note 4, Derivative Financial Instruments, to the Partnership’s financial statements included in this report.

·In ~~MMcf~~general, –the ~~One~~Managing ~~million~~General ~~cubic~~Partner ~~feet~~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, the Managing General Partner 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 ~~MMcfe~~wells –in ~~One~~the ~~million~~Partnership’s ~~cubic~~Wattenberg ~~feet~~Field ofand, to a significantly lesser extent, the Grand Valley Field wells, produce crude oil as well as natural gas ~~equivalents~~and NGLs. The Managing General Partner 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.

~~For~~Transportation ~~more information concerning the Partnership’s 2009~~ and 2008 production volumes and costs, which include severance and ad valorem taxes as reflected in the Partnership’s statements of operations accompanying this report, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations in this report.Gathering

~~Commodity Price Risk Management~~ The Partnership’s ~~production~~natural ~~sold~~gas inand NGLs are transported through the ~~spot~~Managing ~~market~~General Partner’s and ~~under~~third ~~market~~party ~~index~~gathering ~~contracts~~systems isand ~~subject~~pipelines, toand ~~market~~the ~~price~~Partnership ~~fluctuations. PDC~~incurs processing, asgathering ~~Managing~~and ~~General~~transportation ~~Partner~~expenses onto ~~behalf~~move of the Partnership’s ~~through~~natural ~~the~~gas ~~D&O~~and ~~Agreement,~~related ~~uses~~NGLs ~~derivative~~from ~~instruments~~the ~~for~~wellhead to a ~~portion~~purchaser-specified ofdelivery ~~the~~point. These ~~Partnership’s~~expenses ~~committed~~vary based on the volume and ~~anticipated~~distance ~~oil~~shipped, and ~~natural~~the ~~gas~~fee ~~sales~~charged toby ~~achieve~~the athird-party ~~more~~processor ~~predictable~~or ~~cash~~transporter. Capacity ~~flow~~on ~~and~~these togathering ~~reduce~~systems ~~exposure~~and topipelines ~~fluctuations~~is inoccasionally ~~oil~~limited and ~~natural~~at ~~gas~~times ~~commodity~~unavailable ~~prices. Since~~because ~~the~~of ~~Partnership~~repairs ~~manages~~or ~~price~~improvements, ~~risk~~or onas ~~only~~ a ~~portion~~result of ~~its~~priority ~~future~~transportation ~~estimated~~agreements ~~production,~~with ~~future~~other ~~production~~gas ~~not~~transporters. While ~~covered~~the byManaging ~~derivatives~~General isPartner’s ~~subject~~ability to market the ~~full~~Partnership’s ~~fluctuation~~natural ofgas ~~market~~and ~~pricing. The~~NGLs ~~Partnership's~~have ~~policies~~been ~~prohibit~~only ~~the~~infrequently ~~use~~limited ofor ~~derivative~~delayed, ~~financial~~if ~~instruments~~transportation ~~for~~space ~~speculative~~is ~~purposes~~restricted ~~and~~or ~~permit~~is ~~utilization~~unavailable, ofthe ~~derivatives~~Partnership’s ~~only~~cash ifflow ~~there~~from isthe anaffected ~~underlying~~properties ~~physical~~could ~~position~~be adversely affected. ~~For~~In ~~more~~order ~~information~~to onmeet pipeline specifications, the ~~Partnership’s~~Managing ~~derivative~~General ~~financial~~Partner ~~instruments~~is required, ~~see~~in ~~Item~~some 7cases, ~~Management~~to process the Partnership’s ~~Discussion~~natural ~~and~~gas ~~Analysis~~before ofit ~~Financial~~can ~~Condition~~be ~~and~~transported. The ~~Results~~Managing General Partner typically contracts with third parties in the Grand Valley area of ~~Operations−Commodity~~the ~~Price~~Rocky ~~Risk~~Mountain ~~Management,~~Region ~~Net~~for ~~and~~firm ~~Liquidity~~transportation ~~and~~of ~~Capital~~the ~~Resources~~Partnership’s natural gas and NGLs.

Derivative financial instruments employed for risk management generally consist of “collars,” “swaps” and “basis swaps” on the possible range of prices realized for the sale of natural gas and oil and are New York Mercantile Exchange, or NYMEX-traded and Colorado Interstate Gas Index, or CIG, based contracts for Colorado natural gas and oil production. PDC, as Managing General Partner of the Partnership, enters into derivative transactions on behalf of the Partnership in the same manner in which it enters into transactions for itself.13-

·Table ~~Collars~~Of 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.Contents

· 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 index price and contract price are the same, no payment is due to or from the counterparty.

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Index

Historically, the Partnership participated on a pro-rata basis, in all derivative transactions entered into by the Managing General Partner in a given area. The Partnership’s allocation of derivative positions was based on the Partnership’s percentage of estimated production to total estimated production from a given area on a monthly basis. The transactions were on a production month basis. Prior to September 30, 2008, as estimated future production volumes increased due to continued drilling and wells placed into production, the allocation of derivative positions between PDC’s corporate interests and the Partnership, changed on a pro-rata basis. Effective September 30, 2008, PDC changed the allocations procedure whereby the allocation of derivative positions at that date between PDC and each partnership was set at a fixed quantity. For positions entered into subsequent to September 30, 2008, specific designations of the quantities between the Managing General Partner’s corporate interests and each sponsored drilling partnership, including this Partnership, were allocated and fixed at the time the positions were entered into based on estimated future production levels and other factors. Therefore, the Managing General Partner and the sponsored drilling Partnership may not participate on a pro-rata basis or at all in derivative transactions initiated by the Managing General Partner.

All derivative assets and liabilities are recorded on the balance sheets at fair value. PDC, as Managing General Partner, has elected not to formally designate any of the Partnership’s derivative instruments as hedging instruments and therefore, the Partnership does not use hedge accounting. Accordingly, the Partnership is required to recognize changes in the fair value of the Partnership’s derivative instruments in earnings each reporting period and therefore, has the potential for significant earnings volatility. Changes in the fair value of derivative instruments related to the Partnership’s natural gas and oil sales are recorded in the line caption “Commodity price risk management, net” in the Partnership’s statements of operations. For more information regarding the Partnership’s derivative financial instruments and their accounting, see Note 4, Fair Value Measurements and Note 5, Derivative Financial Instruments to the Partnership’s accompanying financial statements included in this report.

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’s 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. The Partnership experienced an approximate 10% to 15% curtailment of production volumes in the Piceance Basin due to limited compression and pipeline capacity throughout most of the fourth quarter in 2008. This interruption, due to third party infrastructure, was remediated in early 2009.

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. ~~oil~~natural gas, NGLs and ~~natural~~crude ~~gas~~oil demand and disrupted global credit markets, which third-party entities access for pipeline expansion financing.

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Index

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

The Managing General Partner, on behalf of the Partnership 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. The Managing General Partner 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. The Managing General Partner 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.

The Managing General Partner 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.

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Table Of Contents

The Partnership is subject to price fluctuations for natural gas and crude oil sold in the spot market and under market index contracts. The Managing General Partner continues to evaluate the potential for reducing these risks by entering into derivative transactions. In addition, the Managing General Partner 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. The Managing General Partner 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. The Managing General Partner 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, the Managing General Partner 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, the Managing General Partner is unable to predict the future cost or effect of complying with such regulations.

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Table Of Contents

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.

The Managing General Partner 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 the Managing General Partner 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. The Managing General Partner 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.

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Table Of Contents

Environmental Matters

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, the Managing General Partner 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.

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Table Of Contents

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 refracturing operations. Additional laws, regulations or other changes could significantly reduce the Partnership’s future refracturing 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 refracturing.

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:

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Table Of Contents

The Dodd-Frank Act may decrease the Managing General Partner’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 Partner cash distributions or fewer completed Codell formation refracturing activities and therefore, decreased Partnership’s proved reserves and future production.

ii.

The Managing General Partner 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 the Managing General Partner 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 ~~oil and~~ natural gas~~. The~~ ~~Partnership competes with entities having financial~~ and ~~human~~crude ~~resources substantially larger than those available to the Partnership~~oil. Because there are thousands of ~~oil~~natural gas and ~~natural~~crude ~~gas~~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 the Managing General Partner’s management and professional staff generally enables the Partnership to compete effectively. As a result of ~~Federal~~the ~~Energy~~well-publicized ~~Regulatory~~turmoil ~~Commission,~~in orthe ~~FERC~~financial and commodity markets in late 2008, resultant industry slowdown throughout 2009 and ~~Congressional~~the ~~deregulation~~Managing ofGeneral Partner’s cost reduction initiatives, the Partnership experienced overall reductions in its 2009 natural gas, NGLs and crude oil production costs. During 2010, the Managing General Partner 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 Item 7, 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 ~~the~~its ~~past~~area of operations. Nevertheless, ~~prices~~the ~~are~~Partnership’s ~~generally~~results ~~determined~~of operations and distributable cash flows could be materially adversely affected by ~~competitive~~the ~~supply-~~uncertainty in ascertaining the ultimate depth and~~-demand~~ ~~market~~duration ~~forces~~of the current economic environment.

~~The~~As ~~marketing~~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 ~~oil~~natural gas and ~~natural~~crude ~~gas~~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 ~~crude~~natural ~~oil~~gas and ~~natural~~crude ~~gas~~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, the Managing General Partner 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 ~~oil~~natural gas, NGLs and ~~natural~~crude ~~gas~~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 with some increasing role played by liquefied natural gas, or LNG, importation, crude oil pricing is subject to global supply~~19-demand influences including the presence of the Organization of Petroleum Exporting Countries, or OPEC, whose members establish prices and production quotas for petroleum products from time to time, with the intent of reducing the current global oversupply caused by the global economic downturn while maintaining or increasing price levels. The Managing General Partner is unable to predict what effect, if any, future OPEC actions will have on the quantity of, or prices received for, oil and natural gas produced and sold from the Partnership's wells.

-Table 11Of -Contents

~~Index~~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. The Managing General Partner is unable to predict what effect, if any, future OPEC actions will have on the quantity of, or prices received for, 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 Agreement, PDC, as Managing General Partner, 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 Investor Partners. 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 Investor Partners, 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 ~~oil~~natural gas and ~~natural~~crude ~~gas~~oil wells in which the Partnership owns an interest, including the initial drilling, testing, completion, and equipping of wells; subsequent ~~well recompletion~~refracturing, where economical, and ultimate evaluation for abandonment. Further, ~~while~~ the Partnership has the right to take in-kind and separately dispose of its share of all ~~oil~~natural gas, NGLs and ~~natural~~crude ~~gas~~oil produced from the Partnership’s wells,. ~~the~~The Partnership designated PDC as its ~~oil~~natural gas, NGLs and ~~natural~~crude ~~gas~~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 ~~oil~~natural gas, NGLs and ~~natural~~crude ~~gas~~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 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.

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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 ~~involve~~include a variety of operating risks, including but not limited to fire, explosions, blowouts, pipe failure, casing collapse, ~~and~~ abnormally pressured formations ~~which could result in injury~~, ~~loss of life or suspension of operations,~~ and environmental hazards such as ~~natural~~ gas leaks, ruptures and discharges of ~~toxic~~natural gas ~~which could result in environmental damage and clean-up obligations~~. ~~PDC,~~The inoccurrence ~~its~~of ~~capacity~~any asof ~~operator,~~these ~~has~~could ~~purchased~~result ~~various~~in ~~insurance~~substantial ~~policies,~~losses ~~including~~to ~~worker’s~~us ~~compensation,~~due ~~operator's~~to ~~bodily~~ injury ~~liability~~ and ~~property~~loss ~~damage~~of ~~liability insurance~~life, ~~employer's~~severe ~~liability~~damage ~~insurance,~~to ~~automobile public liability insurance~~ and ~~operator's~~destruction ~~umbrella~~of ~~liability~~property, ~~insurance~~natural resources and ~~intends to maintain these policies subject to PDC's analysis of their premium costs~~equipment, ~~coverage~~pollution and other ~~factors. During~~environmental ~~drilling operations~~damage, ~~the~~clean-up ~~Managing General Partner maintained public liability insurance of not less than $10 million; however~~responsibilities, ~~PDC~~regulatory ~~may~~investigation ~~at its sole discretion in other situations, increase or decrease policy limits, change types of insurance~~ and ~~name~~penalties ~~PDC~~ and ~~the~~suspension ~~Partnership,~~of ~~individually or together, parties to the insurance as deemed appropriate under the circumstances, which may vary materially~~operations. AsThe ~~operator of the~~ Partnership'’s ~~wells,~~gathering ~~PDC~~and ~~requires~~distribution ~~its~~operations ~~subcontractors~~are subject to ~~carry~~the ~~liability~~many ~~insurance~~hazards ~~coverage~~inherent ~~with~~in ~~respect to~~ the ~~subcontractors’ activities~~industry. ~~PDC’s~~These ~~management,~~hazards ininclude ~~its~~damage ~~capacity~~to ~~as Managing General Partner~~wells, ~~believes~~pipelines ~~that~~and inother ~~accordance~~related ~~with customary industry practice~~equipment, ~~adequate~~damage ~~insurance,~~to ~~including~~property ~~insurance~~caused by ~~PDC’s subcontractors~~hurricanes, ~~has been provided to the Partnership with coverage sufficient to protect the Investor Partners against the foreseeable risks of operation~~floods, ~~drilling,~~fires ~~recompletions~~ and ~~reworks~~other ~~and~~acts ~~ongoing~~of ~~productions operations. However~~God, ~~there~~inadvertent ~~can~~damage befrom noconstruction ~~assurance that this insurance will be adequate to cover all losses or exposure for liability and thus~~equipment, ~~the~~leakage ~~occurrence~~ of anatural ~~significant~~gas ~~event~~and ~~not~~other ~~fully insured against~~hydrocarbons, ~~could~~fires ~~materially~~and ~~adversely~~explosions ~~affect Partnership operations~~ and ~~financial~~other ~~condition. Furthermore,~~hazards ~~the~~that ~~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 also result in ~~significantly~~personal ~~lower~~injury ~~regional~~and ~~prices~~loss ~~or the Partnership’s inability to deliver natural gas. As~~ of ~~the date of this filing~~life, ~~the~~pollution ~~Managing~~and ~~General~~suspension ~~Partner~~of ~~has no knowledge that such events have occurred~~operations.

-Any 12significant -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.

~~Index~~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, the Managing General Partner 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, 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 Investor Partners against the foreseeable risks of operation, drilling, refracturing 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, the Managing General Partner has no knowledge that such events have occurred.

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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 isand 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. Through December 31, 2008, PDC sold 100% of the crude oil from the Partnership’s wells to Teppco Crude Oil, LP (“Teppco”). Beginning January 1, 2009, Suncor became the Partnership’s primary oil purchaser.

Industry Regulation

While the prices of oil and natural gas 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.

The availability of a ready market for oil and natural gas 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 oil and natural gas 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 oil and natural gas, to prevent waste of oil and natural gas, to protect rights of 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.

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. Current federal and state proposed regulations expected to impact the industry, if enacted, include the following:

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Index

· Congressional legislation which could 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 could affect the Partnership and the third parties that process the Partnership’s natural gas and oil.

· Federal regulatory proposals, which could limit the use of over-the-counter (OTC) derivatives, including the oil and gas price hedging the Managing General Partner currently uses. Limits on the use of OTC instruments could impair the Managing General Partner’s use of these derivatives and could limit the Partnership’s ability to protect its cash flows and reduce commodity price risk.

· 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 well recompletions.

Environmental Regulation

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 natural gas industry in general, our business and prospects could be adversely affected. In 2009, the State of Colorado’s Oil and Gas Conservation Commission implemented new broad-based environmental and wildlife protection regulations for the industry which are expected to increase the Partnership’s well recompletion costs and ongoing level of natural gas and oil production costs. See Note 9, Commitments and Contingencies−Other to the Partnership’s accompanying financial statements to this report.

Partnership expenses relating to preserving the environment have risen over the past two years and are expected to continue. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells. While environmental regulations have had no materially adverse effect on its operations to date, 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 Partnership operations.

The Partnership generates wastes 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 our 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’s operations may be subject to the Clean Air Act, or CAA, and comparable state and local requirements. The State of Colorado has implemented new air emission regulations in 2009, which affect the industry, including the Partnership’s operations.

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Index

Available Information

The Partnership is subject to the reporting and information requirements of the Securities Exchange Act of 1934, as amended, and is as a result obligated to file periodic reports, proxy statements and other information with the SEC. The SEC maintains a website that contains the annual, quarterly, and current reports, proxy and information statements, and other information regarding the Partnership, which the Partnership electronically files with the SEC. The address of that site is http://www.sec.gov. The Central Index Key, or CIK, for the Partnership is 0001326539. You can read and copy any materials the Partnership files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1850, Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

Number of total and full-time employees

The Partnership has no employees and relies on the Managing General Partner 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. See Item 11, Executive Compensation and Item 13, Certain Relationships and Related Transactions, and Director Independence for a discussion of compensation paid by the Partnership to the Managing General Partner.

~~Item 1A. Risk Factors~~-22-

~~Not~~Table ~~Applicable~~Of Contents

~~Item~~ ITEM 1B1A. RISK ~~Unresolved Staff Comments~~FACTORS

~~None~~Not applicable.

~~Item~~ITEM 21B. UNRESOLVED ~~Properties~~STAFF COMMENTS

Information regarding the Partnership’s wells, production, proved reserves and acreage are included in Item 1 and Note 2, Summary of Significant Accounting Policies, to the Partnership’s financial statements included in this reportNone.

~~Item~~ITEM 32. ~~Legal Proceedings~~ PROPERTIES

Information regarding the Partnership’s wells, production, proved reserves and acreage are included in Item 1, Business of this report and Note 2, Summary of Significant Accounting Policies, to the Partnership’s financial statements included in this report.

ITEM 3. LEGAL PROCEEDINGS

The Registrant is not currently subject to any material pending legal proceedings.

See Note 97, Commitments and Contingencies to the accompanying financial statements for additional information related to litigation.

~~Item~~ITEM 4. [~~Reserved~~REMOVED AND RESERVED]

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~~Index~~Table Of Contents

PART II

~~Item~~ITEM 5. ~~Market~~MARKET ~~for~~FOR ~~Registrant~~REGISTRANT’sS ~~Common~~COMMON ~~Equity~~EQUITY, ~~Related~~RELATED ~~Stockholder~~STOCKHOLDER ~~Matters~~MATTERS ~~and~~AND ~~Issuer~~ISSUER ~~Purchases~~PURCHASES ofOF ~~Equity~~EQUITY ~~Securities~~SECURITIES

At December 31, ~~2009~~2010, the Partnership had 1,~~494~~502 Investor Partners holding 1,996.87 units and one Managing General Partner. The investments held by the Investor Partners are in the form of limited partnership interests. Investor Partners' interests are transferable; however, no assignee of units in the Partnership can become a substituted partner without the written consent of the transferor and the Managing General Partner. As of December 31, ~~2009~~2010, the Managing General Partner has repurchased 2332.7521 units of Partnership interests from Investor Partners.

Market. There is no public market for the Partnership units nor will a public market develop for these units in the future. Investor Partners may not be able to sell their Partnership interests or may only be able to sell ~~them~~their ~~only~~Partnership interest for less than fair market value. No transfer of a unit may be made unless the transferee satisfies relevant suitability requirements, as imposed by federal and state law or the Partnership Agreement. The Partnership may require that the transferor provide an opinion of legal counsel stating that the transfer complies with applicable securities laws. A sale or transfer of units by an individual investor partner requires PDC’s, ~~as Managing General Partner,~~ prior written consent. For these and other reasons, an individual investor partner must anticipate that he or she ~~will~~may have to hold his or her partnership interests indefinitely and ~~will~~may not be able to liquidate his or her investment in the Partnership. Consequently, an individual investor partner must be able to bear the economic risk of investing in the Partnership for an indefinite period of time.

Cash Distribution Policy. PDC plans to make distributions of Partnership cash on a monthly basis, but no less often than quarterly, subject to funds being available for distribution. PDC will make cash distributions of 80% of ~~available~~distributable cash to the Investor Partners, including any Investor Partner units purchased by the Managing General Partner, and 20% of ~~available~~distributable cash to the Managing General Partner, throughout the term of the Partnership. Cash is distributed to the Investor Partners and PDC currently as a return of capital in the same proportion as their proportional interest in the net income of the Partnership. Distributable cash, also referred to as distributable cash flows, has generally been the Partnership's net cash flows provided by operating activities less any net cash used in investing activities.

PDC cannot presently predict amounts of future cash distributions, if any, from the Partnership. However, PDC expressly conditions any ~~distribution~~and all future cash distributions upon the Partnership having sufficient cash available for distribution. Sufficient cash available for distribution is defined to generally ~~mean~~as cash generated by the Partnership in excess of the amount the Managing General Partner determines is necessary or appropriate to provide for the conduct of the Partnership's business, to comply with applicable law, to comply with any other agreements or to provide for future distributions to unit holders. In this regard, PDC reviews the accounts of the Partnership at least quarterly for the purpose of determining the sufficiency of distributable cash available for distribution. Amounts will be paid to Investor Partners only after payment of fees and expenses to the Managing General Partner and its affiliates and only if there is sufficient cash available. The ability of the Partnership to make or sustain cash distributions depends upon numerous factors. PDC can give no assurance that any level of cash distributions to the Investor Partners of the Partnership will be attained, that cash distributions will equal or approximate cash distributions made to investor partners of prior drilling programs sponsored by PDC, or that any level of cash distributions can be maintained.

The ability of the Partnership to make or sustain cash distributions depends upon numerous factors. PDC can give no assurance that any level of cash distributions to the Investor Partners of the Partnership will be attained, that cash distributions will equal or approximate cash distributions made to investor partners of prior drilling programs sponsored by PDC, or that any level of cash distributions can be maintained. Fully developing all of the Partnership’s properties would require substantial capital expenditures. Because of the restrictions set forth in the 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.

Implementation of the Well Refracturing Plan would reduce or eliminate Partnership cash distributions to investors while the work is being conducted and paid for. All funds withheld for the Well Refracturing Plan reduce the cash distributions to both the managing General Partner and Investor Partners in the same proportion as their proportional interest in the net income of the Partnership. These funds are held in the Partnership's bank account which is included in the Partnership's financial statements in "Cash and cash equivalents." The intended use of this cash is for executing the Well Refracturing plan; however, if an unexpected operational need would arise, the funds retained may be used to fulfill this obligation. The funds will be transferred to the managing General Partner at the time these costs have been incurred. If the Managing General Partner would determine to abandon or delay a significant portion of the Well Refracturing Plan, any funds which were withheld and not used for these Partnership activities would be distributed to the Managing General Partner and Investor Partners based on their proportional share. Depending upon the level of withholding and the results of operations, it is possible that investors could have taxable income from the Partnership without any corresponding distributions in future years. If PDC were to be successful in the future acquisition effort of this Partnership, liquidation of the Partnership and a final payout would result in cessation of all future cash payments. The exchange by an investor partner of limited partnership units for cash pursuant to any merger would be a taxable transaction for U.S. federal income tax purposes. The effects of a potential acquisition may be different for each investor partner. For more information concerning the Partnership’s Well Refracturing Plan see Item 1, Business – Operations, Drilling and Other Activities - Well Refracturing Plan. For additional information regarding PDC’s disclosed partnership acquisition intensions, refer to the section entitled Recent Developments−PDC Sponsored Drilling Program Acquisition Plan on page 3 and Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−PDC Sponsored Drilling Program Acquisition Plan.

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Non-affiliated Investor Partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the Well Refracturing Plan and any potential merger. The above discussion is not intended as a substitute for careful tax planning, and non-affiliated Investor Partners should depend upon the advice of their own tax advisors concerning the effects of the Well Refracturing Plan and any potential merger.

The following table presents cash distributions made to the Partnership’s investors for the periods described:

	Cash
Period	Distributions
For the year ended December 31, 2009	$	5,144,303
For the year ended December 31, 2010	$	3,356,120
For the year ended December 31, 2008		5,964,174
For the year ended December 31, 2009		5,144,303
For the period from the Partnership's inception to December 31, 2009	$	40,054,740
For the period from the Partnership's inception to December 31, 2010	$	43,410,860

The volume and rate of production from producing ~~properties~~wells naturally declines with the passage of time and is generally not subject to the control of management. The cash flow generated by the Partnership's activities and the amounts available for distribution to the Partnership's Investor Partners will, therefore, decline in the absence of significant increases in the prices that the Partnership receives for its ~~oil~~natural gas, NGLs and ~~natural~~crude ~~gas~~oil production, or significant increases in the production of ~~oil~~natural gas, NGLs and ~~natural~~crude ~~gas~~oil from the successful ~~additional~~refracturing ~~development~~ of these properties, if any. ~~When~~The ~~the Partnership decides to develop its wells further, the~~ funds necessary for ~~that~~any ~~development~~Codell formation refracturing would ~~come~~be withheld from the Partnership's distributable cash flows. As a result, there may be a decrease in the funds available for distribution, and the distributions to the Investor Partners ~~may~~would then decrease. For more information regarding the refracturing of the Partnership’s Wattenberg Field wells see Item 1, Business−Operations, Drilling and Other Development Activities -Well Refracturing Plan on page 6. For more information concerning the Partnership’s cash flows from operations see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Liquidity and Capital Resources.

-Unit 16Repurchase Program. Investor Partners may request that the Managing General Partner repurchase limited partnership 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 up 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. If accepted, repurchase requests are fulfilled by the Managing General Partner on a first-come, first-serve basis. In addition to the above repurchase program, individual investor partners periodically offered and PDC repurchased units on a negotiated basis before the third anniversary of the date of the first cash distribution.

~~Index~~The following table presents information about the Managing General Partner’s limited partner unit repurchases under the unit repurchase program during the periods described below. As of December 1, 2010, the Managing General Partner suspended the opportunity for an individual non-affiliated Investor Partner to request that PDC repurchase their respective limited partnership units under the terms of the program, pending the outcome of the proposed Merger Agreement.

Unit Repurchase Program. 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 “publically 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. There were no limited partner unit repurchases by the Managing General Partner during the three months ended December 31, 2009.

Period	Total Number of Units Repurchased		Average Price Paid per Unit

October 1−31, 2010		3.00	$	5,897
November 1−30, 2010		1.00		6,190
December 1−31, 2010		-		-
Total fourth quarter Unit Repurchase Program repurchases		4.00

In addition to the above repurchase program, individual investor partners periodically offered and PDC repurchased units on a negotiated basis before the third anniversary of the date of the first cash distribution.-25-

~~Item~~Table 6.Of ~~Selected Financial Data~~Contents

~~Not~~ITEM ~~applicable~~6. SELECTED FINANCIAL DATA

~~Item~~Not 7applicable. ~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~

~~The~~ITEM ~~following~~7. ~~discussion and analysis, as well as other sections in this Form 10-K, should be read in conjunction with the Partnership~~MANAGEMENT’sS ~~accompanying~~DISCUSSION ~~financial~~AND ~~statements~~ANALYSIS ~~and~~OF ~~related~~FINANCIAL ~~notes~~CONDITION toAND ~~the~~RESULTS ~~financial~~OF ~~statements included in this report. Further, the Partnership encourages the reader to revisit the Special Note Regarding Forward-Looking Statements on page 1 of the report.~~OPERATIONS

The following discussion and analysis, as well as other sections in this Form 10-K, should be read in conjunction with the Partnership’s accompanying financial statements and related notes to the financial statements included in this report. Further, the Partnership encourages the reader to revisit the Special Note Regarding Forward-Looking Statements on page one of the report.

Partnership Overview

PDC 2005-A Limited Partnership engages in the development, production and sale of ~~oil~~natural gas, NGLs and ~~natural~~crude ~~gas~~oil. The Partnership began ~~oil~~natural gas and ~~gas~~crude oil operations in February 2005 and ~~currently~~ operates 4849 gross (4344.54 net) productive wells located in the ~~state~~Rocky ofMountain ~~Colorado. One~~Region ~~additional Partnership Wattenberg Field well (0.9 net) is temporarily shut-~~in atthe ~~December~~state ~~31,~~of ~~2009, due to operational issues~~Colorado. The Managing General Partner markets the Partnership’s natural gas production to commercial end users, interstate or intrastate pipelines or local utilities, 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 ~~through~~in accordance with the D&O Agreement, ~~may~~is authorized to enter into multi-year ~~contracts~~fixed ~~which~~price ~~generally~~contracts ~~have monthly index-based pricing provisions,~~ 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 ~~could~~tend to be affected by demand factors with a seasonal component.

~~The~~Recent Partnership’s wells will produce until they are depleted or until they are uneconomical to produce; however, Partnership well recompletions in the Codell formation of Wattenberg Field wells may provide for additional reserve development and production. These well recompletions generally occur five to ten years after initial well drilling so that well resources are optimally utilized and would be expected to occur within a favorable general economic environment and commodity price structure. The Managing General Partner has developed a plan to initiate recompletion activities during 2011. This plan includes notifying investor partners that funds to begin these recompletions will be withheld from future distributable cash flows of the Partnership resulting from both current production and any increased production due to recompletion activities. The funds retained necessary for the Partnership to pay for the recompletion costs will materially reduce, up to 100%, distributable cash flows for a period of time not to exceed five years. If any or all of the Partnership’s Wattenberg wells are not recompleted, the Partnership will experience a reduction in proved reserves currently assigned to these wells. Both the number of recompletions and the timing of recompletions will be based on the availability of cash withheld from distributions. The Managing General Partner believes that, based on projected recompletion costs and projected cash withholding, all partnership recompletions can be completed. Current estimated costs for these well recompletions are between $150,000 and $200,000 per recompletion. As the optimal period approaches, the Managing General Partner will re-evaluate the feasibility of commencing those recompletions based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the recompletion.Developments

-PDC 17Sponsored -Drilling Program Acquisition Plan

~~Index~~PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue, beginning in the fall of 2010 and extending through the next three years, the acquisition of the limited partnership units (the “Acquisition Plan”) held by Investor Partners of that partnership other than PDC or its affiliates (“non-affiliated Investor Partners”), in the limited partnerships that PDC has sponsored, including this Partnership. For additional information regarding PDC’s intention to pursue acquisitions of PDC sponsored partnerships, refer to the disclosure included in Items 2.02, 7.01 and/or 8.01 of PDC’s Forms 8-K dated March 4, 2010, June 9, 2010, July 15, 2010 and November 17, 2010. However, such information shall not, by reason of this reference, be deemed to be incorporated by reference in, or otherwise be deemed to be part of, this report. Under the Acquisition Plan, any existing or future merger offer will be subject to the terms and conditions of the related merger agreement, and such agreement does or will likely contemplate the partnership being merged with and into a wholly-owned subsidiary of PDC. Each such merger will also be subject to, among other things, PDC having sufficient available capital and the approval by a majority of the limited partnerships units held by the non-affiliated Investor Partners of each respective limited partnership. Consummation of any proposed merger of a PDC sponsored limited partnership under the Acquisition Plan will likely result in the termination of the existence of that partnership and the right of non-affiliated Investor Partners to receive a cash payment for their limited partnership units in that partnership.

~~2009~~The ~~Overview~~feasibility and timing of any future purchase offer by PDC to any additional partnership depends on that partnership’s suitability in meeting a set of criteria that includes, but is not limited to, the following: age and productive-life stage characteristics of the partnership’s well inventory; favorability of economics for Wattenberg Field well refracturing; and SEC reporting compliance status and timing associated with gaining all necessary regulatory approvals required for a merger and repurchase offer. There is no assurance that any merger and acquisition will occur, as a result of PDC’s proposed repurchase offers to the 2005 partnerships, including this Partnership, or any potential proposed repurchase offer to any other of PDC’s various public limited partnerships, should they occur.

Even with natural gas prices rebounding somewhat in the last two months of 2009 from earlier in the year, the Partnership continued to experience a depressed natural gas commodity pricing market throughout 2009 compared to 2008. The Partnership’s production decreased to 903 MMcfe for the 2009 annual period compared to 957 MMcfe for the same 2008 period, a decrease of 6%. The Partnership’s average sales price for 2009 declined to $3.62 per Mcfe, a decrease of 53% from the annual sales price a year ago. While the significant changes in commodity prices have impacted the Partnership’s results of operations, the Managing General Partner believes that managing the Partnership’s operations by partially reducing the negative impacts of lower prices through the Partnership’s derivative positions, was successful. Although the Partnership’s 2009 natural gas and sales revenues declined by $4.1 million compared to 2008, the Partnership’s annual cash flows provided by operating activities decreased by only $1.0 million, or 17%, primarily benefited by the Partnership’s increase in realized derivative gains for the 2009 annual period to $2.5 million and the reduction in “Due from Managing General Partner –Other, Net” of $1.2 million. These realized derivative gains added $2.78 per Mcfe to the Partnership’s average sales price noted above.-26-

-Table 18Of -Contents

~~Index~~During 2010, PDC acquired four affiliated partnerships: PDC 2004-A Limited Partnership, PDC 2004-B Limited Partnership, PDC 2004-C Limited Partnership and PDC 2004-D Limited Partnership. PDC purchased these partnerships for the aggregate amount of $34.8 million. In November 2010, PDC and DP 2004 Merger Sub, LLC, a wholly-owned subsidiary of PDC (“DP Merger Sub”), entered into separate merger agreements with this Partnership, PDC 2005-B Limited Partnership and Rockies Region Private Limited Partnership (collectively, the “2005 partnerships”).

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 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;

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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.

If the merger is not completed, the anticipated non-affiliated Investor Partner merger benefits that include unit liquidity and elimination of Schedule K-1 tax reports in the Partnership will not be realized and the Partnership will continue the existing business plan to optimally develop and cost-effectively operate the Partnership’s natural gas and oil reserves.This plan encompasses the implementation of the Well Refracturing Plan, more fully outlined below. The information presented in this Annual Report on Form 10-K for the year ended December 31, 2010 does not give effect to the proposed Merger Agreement.

Well Refracturing Plan. The Managing General Partner has prepared a plan for the Partnership’s Wattenberg Field wells which may provide for additional reserve development and natural gas, NGLs and crude oil production (the “Well Refracturing Plan”). The Well Refracturing Plan consists of the Partnership’s refracturing of wells currently producing in the Codell formation. Under the Well Refracturing Plan, the Partnership plans to initiate refracturing activities during 2012. Refracturing, or “refracing,” activities consist of a second hydraulic fracturing treatment in a current production zone, all within an existing well bore.

Refracturing 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 refracturing would be expected to occur based on a favorable general economic environment and commodity price structure. The Managing General Partner has the authority to determine whether to refrac the individual wells and to determine the timing of any refracturing activity. The timing of the refracturing can be affected by the desire to optimize the economic return by refracturing 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 have been at modeled economics; however, all refracturings have not been economically successful and similar future refracturing activities may not be economically successful. If the refracturing work is performed, PDC will charge the Partnership for the direct costs of refracturing, and the Investor Partners and the Managing General Partner will each pay their proportionate share of costs based on the ownership sharing ratios of the Partnership from funds retained by the Managing General Partner from distributable cash flows.

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During the fourth quarter 2010, the Managing General Partner began withholding funds from several of the PDC sponsored partnerships, on a pro-rata basis allocated to the Managing General Partner and Investor Partners based on their proportional ownership interest, from distributable cash flows of the Partnership resulting from current production. The funds retained are necessary for the Partnership to pay for refracturing costs and will materially reduce, up to 100%, distributable cash flows of the Partnership for a period of time not to exceed five years. If any or all of the Partnership’s Wattenberg wells are not refractured, the Partnership will experience a reduction in proved reserves currently assigned to these wells. Both the number and timing of the refracturing activities will be based on the availability of cash withheld from Partnership distributions. The Managing General Partner believes that, based on projected refracturing costs and projected cash withholding, all scheduled Partnership refracturing activity will be completed within a five year period.

Current estimated costs for these well refracturings are between $175,000 and $240,000 per activity. As of December 31, 2010, this Partnership has scheduled to complete 35 refracturing opportunities. This increase from 33 potential refracturing opportunities as of December 31, 2009 is due to an increase in estimated future distributable cash flows based on current pricing and well economics. Total withholding for these activities from the Partnership’s distributable cash flows is estimated to be between $6.1 million and $8.4 million. The Managing General Partner will continually evaluate the timing of commencing these refracturing 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 December 31, 2010, $60,000 has been withheld from the Partnership distributions for this refracturing. Cumulatively, $100,000 has been withheld from Partnership distributions through February 28, 2011.

Implementation of the Well Refracturing Plan would reduce or eliminate Partnership distributions to the Managing General Partner and Investor Partners while the work is being conducted and paid for. Depending upon the level of withholding and the results of operations, it is possible that the Managing General Partner and Investor Partners could have taxable income from the Partnership without any corresponding distributions in future years. Non-affiliated Investor Partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the Well Refracturing Plan. The above discussion is not intended as a substitute for careful tax planning, and non-affiliated Investor Partners should depend upon the advice of their own tax advisors concerning the effects of the Well Refracturing Plan.

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2010 and 2009 Partnership Overview

Natural gas, NGLs and crude oil sales increased by $0.8 million, or 24%, during the 2010 annual period compared to 2009, even though production volumes decreased 8% period-to-period. This revenue increase was supported by the improved commodity price environment and the increase in the Partnership’s crude oil production as a percentage of total production. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $4.87 during 2010 compared to $3.62 for 2009. Comparatively, the total per Mcfe price realized, consisting of the average sales price and realized derivative gains, decreased to $5.78 during 2010 from $6.40 during 2009. This decrease was primarily due to realized derivative gains from natural gas and crude oil sales contributing only $0.91 per Mcfe or $0.8 million to the 2010 total revenues as compared to $2.78 per Mcfe or $2.5 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 $1.5 million in 2010 as compared to unrealized losses of $3.6 million in 2009.

The Partnership’s combined natural gas, NGLs and crude oil production expenses and direct costs−administrative and general, decreased by $0.3 million during 2010. This decrease is primarily the result of lower administrative and general expenses due to lower fees for professional services.

Reporting on NGLs in 2010

As the Partnership embarks on the Well Refracturing Plan, the Managing General Partner 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, 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 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, all of the Partnership’s revenues and production volumes of natural gas, NGLs and crude oil will be presented in a fashion comparable to the 2010 information contained in this report.

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Results of Operations

Summary Operating Results

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. See the previous discussion in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Reporting on NGLs in 2010 for additional details.

	Year Ended December 31,
	2009		2008			Change
	2010		2009			Change
Number of producing wells (end of period)		4849		4948			*1
Production (1)
Production(1)
Natural gas (Mcf)		~~767~~675,~~729~~693		~~804~~767,~~531~~729			-512	%
Oil (Bbl)		22,477		25,353			-11	%
NGLs (Bbl)		3,551		-			*
Natural gas equivalents (Mcfe) (2)		902,591		956,649			-6	%
Subtotal natural gas and NGLs (Mcfe)(2)		696,999		767,729			-9	%
Mcfe per day		2,473		2,621			-6	%
Crude oil (Bbl)		22,506		22,477			0	%
Natural Gas and Oil Sales
Natural gas equivalents (Mcfe)(2)		832,035		902,591			-8	%
Natural gas	$	2,083,298	$	5,157,970			-60	%
Mcfe per day		2,280		2,473			-8	%
Oil		1,184,840		2,252,567			-47	%
Natural Gas, NGLs and Crude Oil Sales
Total natural gas and oil sales	$	3,268,138	$	7,410,537			-56	%
Natural gas	$	2,281,868	$	2,083,298			10	%
Realized Gain (Loss) on Derivatives, net
NGLs		127,763		-			*
Natural gas	$	2,069,976	$	318,317			*
Subtotal natural gas and NGLs		2,409,631		2,083,298			16	%
Oil		438,456		(86,227	)		*
Crude oil		1,643,834		1,184,840			39	%
Total realized gain on derivatives, net	$	2,508,432	$	232,090			*
Total natural gas, NGLs and crude oil sales	$	4,053,465	$	3,268,138			24	%
Average Selling Price (excluding realized gain (loss)on derivatives)
Realized Gain on Derivatives, net
Natural gas (per Mcf)	$	2.71	$	6.41			-58	%
Natural gas	$	576,963	$	2,069,976			-72	%
Oil (per Bbl)		52.71		88.85			-41	%
Crude oil		177,429		438,456			-60	%
Natural gas equivalents (per Mcfe)		3.62		7.75			-53	%
Total realized gain on derivatives, net	$	754,392	$	2,508,432			-70	%
Average Selling Price (including realized gain (loss)on derivatives)
Average Selling Price (excluding realized gain on derivatives)
Natural gas (per Mcf)	$	53.4138	$	62.8171			~~-21~~25	%
Oil (per Bbl)		72.22		85.45			-15	%
NGLs (per Bbl)		35.98		-			*
Natural gas equivalents (per Mcfe)		6.40		7.99			-20	%
Natural gas and NGLs (per Mcfe)		3.46		2.71			28	%
Crude oil (per Bbl)		73.04		52.71			39	%
Natural gas equivalents (per Mcfe)		4.87		3.62			35	%
Average Selling Price (including realized gain on derivatives)
Natural gas (per Mcf)	$	4.23	$	5.41			-22	%
NGLs (per Bbl)		35.98		-			*
Natural gas and NGLs (per Mcfe)		4.28		5.41			-21	%
Crude oil (per Bbl)		80.92		72.22			12	%
Natural gas equivalents (per Mcfe)		5.78		6.40			-10	%
Average cost per Mcfe
Natural gas and oil production cost (3)	$	1.64	$	1.98			-17	%
Natural gas, NGLs and crude oil production cost(3)	$	1.68	$	1.64			3	%
Depreciation, depletion and amortization		3.8719		23.9987			30-18	%
Operating costs and expenses:
Direct costs - general and administrative	$	~~442~~189,~~140~~149	$	~~344~~442,~~410~~140			28-57	%
Depreciation, depletion and amortization	$	32,~~495~~653,~~667~~822	$	23,~~857~~495,~~897~~667			22-24	%
Cash distributions	$	53,~~144~~356,~~303~~120	$	5,~~964,174~~144303			-1435	%

* 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 wethe ~~have~~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, NGLs 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 ~~oil~~natural gas, NGLs and ~~gas~~crude oil operating expenses which include production taxes.

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~~Index~~Table Of Contents

~~Definitions~~Natural ~~used~~Gas, ~~throughout~~NGLs ~~Management’s Discussion~~ and ~~Analysis~~Crude ofOil ~~Financial Condition and Results of Operations.~~Sales

·Changes ~~Bbl~~in –Natural ~~One~~Gas, ~~barrel~~NGLs orand 42Crude UOil Production Volumes.S For the 2010 annual period compared to the 2009 annual period, natural gas, NGLs and crude oil production, on an energy equivalency-basis, decreased 8% due to normal production declines for this stage in the wells’ production life cycle. Additionally, ~~gallons~~Grand ~~liquid~~Valley ~~volume~~Field operational constraints during the year, which was partially offset by one Grand Valley Field’s well’s performance improvement after workover, also contributed to the 2010 production decline.

·Changes ~~MBbl~~in –Natural ~~One~~Gas ~~thousand~~and ~~barrels~~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 $0.3 million, or 16% higher than comparably reported 2009 natural gas sales revenues. Combined production from natural gas and NGLs were 696,999 Mcfe in 2010 compared to 767,729 Mcfe in 2009. This 70,730 Mcfe or 9% reduction in production was more than offset by the higher average selling price for these commodities of $3.46 per Mcfe in 2010 compared to $2.71 in 2009. This $0.75 per Mcfe increase represents a 28% overall price increase from the prior year.

·Changes ~~Mcf~~in –Crude ~~One~~Oil ~~thousand~~Sales. The ~~cubic~~$0.5 ~~feet~~million, or 39%, increase in crude oil sales for the 2010 annual period as compared to the 2009 annual period was a reflection of a higher average sales price per Bbl of 39%, on stable production volumes. The average sales price per Bbl, excluding the impact of realized derivative gains, was $73.04 for the current year annual period compared to $52.71 for the same period a year ago.

·Natural ~~MMcf~~Gas, –NGLs ~~One~~and ~~million~~Crude ~~cubic~~Oil ~~feet~~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 ~~Mcfe~~price –at ~~One~~which ~~thousand~~PDC ~~cubic~~markets ~~feet~~the of natural gas ~~equivalents,~~produced in the Rocky Mountain Region by the Partnership is based on a ~~ratio~~variety of 6prices, ~~Mcf~~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 ~~each~~production ~~barrel~~delivered ofto ~~oil~~other Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which ~~reflects~~is primarily New York Mercantile Exchange, or NYMEX, based, because of the ~~relative~~lack ~~energy~~of ~~content~~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.

~~· MMcfe – One million cubic feet of natural gas equivalents~~-32-

·Table ~~MMbtu~~Of ~~– One million British Thermal Units~~Contents

Natural Gas and Oil Sales

The 56% decrease in total sales in 2009 as compared to 2008 was due to the combined effects of decreased production volumes, on a Mcfe or energy equivalency basis, of 6% and a significantly lower average sales price per Mcfe, of 53%.

Commodity price declines contributed $3.7 million while volume reductions added $0.4 million to the $4.1 million decrease in oil and natural gas sales in 2009 compared to the prior year. The decrease in natural gas and oil sales revenue was partially offset by realized derivative gains during 2009 of $2.5 million. See Commodity Price Risk Management, Net discussion below.

The decrease in natural gas revenues of 60% contrasts to the more moderate reduction in oil revenues of 47% which reflects the less significant reduction in average oil sales prices (41%) as compared to the reduction in natural gas sales prices (58%) during the period. The Partnership expects to experience continued declines in both oil and natural gas production volumes over the wells’ life cycles until the Wattenberg Field wells are recompleted.

Natural Gas and Oil Pricing

Financial results depend upon many factors, particularly the price of oil and natural gas and the Partnership’s ability to market its production effectively. Oil and natural gas prices are among the most volatile of all commodity prices. These price variations have a material impact on the Partnership’s financial results. Oil and natural gas prices also vary by region and locality, depending upon the distance to markets, 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 has resulted in a local market oversupply situation from time to time.

The price the Partnership receives for the natural gas produced in the Rocky Mountain Region is based on a variety 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 Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is primarily 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 recent months and for two out of the last four months become a slight positive differential, which contradicts historical variances.

Like most producers in the region, the Partnership relies on major interstate pipeline companies to construct transmission facilities to increase pipeline capacity to Northeastern U.S and California markets, rendering the timing and availability of these facilities beyond the Partnership’s control. In view of the regional transportation capacity issues cited herein regarding Rocky Mountain regional production, the Partnership believes that pipeline capacity constraints, although significantly moderated, will continue into the immediate future and that the sale of production in the Rocky Mountain Region will continue to be influenced by price. To that end, the Partnership has been able to sell all of its production to date, has not had to significantly curtail its production for long periods of time because of an inability to sell its production because of pipeline deliverability constraints and believes that it will be able to sell all of its future production at market prices.

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Index

Commodity Price Risk Management, Net

~~Natural~~Commodity ~~Gas~~price ~~and~~risk ~~Oil~~management, ~~Sales~~net, ~~Derivative~~includes ~~Instruments. The~~realized ~~Managing~~gains ~~General~~and ~~Partner~~losses onand ~~behalf~~unrealized ofchanges ~~the Partnership~~ in ~~accordance with~~ the ~~D&O~~fair ~~Agreement,~~value ~~uses~~of ~~various~~ derivative instruments related to ~~manage fluctuations in oil and natural gas prices. The Partnership has in place, a series of collars, fixed-price swaps and basis swaps on a portion of~~ the Partnership’s natural gas and crude oil production. ~~Under~~See ~~the~~Note ~~Partnership’s collar arrangements~~3, ifFair ~~the~~Value ~~applicable~~of ~~index~~Financial ~~rises above the ceiling price~~Instruments, ~~the~~and ~~Managing~~Note ~~General Partner pays the counterparty; however~~4, ifDerivative ~~the~~Financial ~~index drops below the floor price~~Instruments, ~~the~~to ~~counterparty pays~~ the ~~Managing General Partner. Under the~~ Partnership’s ~~commodity~~financial ~~swap~~statements ~~arrangements,~~included ifin ~~the~~this ~~applicable~~report ~~index~~for ~~rises~~additional ~~above~~details the swap price, the Managing General Partner pays the counterparty; however, if the index drops below the swap price, the counterparty pays the Managing General Partner. Under the Partnership’s basis protection swaps, if the differential widens, then the counterparty pays the Managing General Partner; however, if the differential narrows, then the Managing General Partner pays the counterparty. Because the Partnership sells all of ~~its physical natural gas and oil at similar prices to~~ the ~~indexes inherent in the~~ Partnership’s derivative ~~instruments,~~financial 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 swapsinstruments.

The following table presents the ~~Partnership’s~~realized and unrealized derivative gains and losses included in commodity price risk management gain (loss) ~~gain~~, net.

	Year Ended December 31,
Commodity price risk management, net	~~2009~~2010			~~2008~~2009
Realized gains (losses)
Realized gain
Oil	$	438,456		$	(86,227	)
Natural Gas	$	576,963		$	2,069,976
Natural Gas		2,069,976			318,317
Crude Oil		177,429			438,456
Total realized gain, net		2754,~~508,432~~392			~~232~~2,~~090~~508,432
Unrealized gains (losses)
Unrealized gain (loss)
Reclassification of realized (gains) losses included in prior periods unrealized		(2,100,436	)		155,289
Reclassification of realized gain included in prior periods unrealized		(25,346	)		(2,100,436	)
Unrealized (loss) gain for the period		(1,495,364	)		2,650,982
Unrealized gain (loss) for the period		1,501,011			(1,495,364	)
Total unrealized (loss) gain, net		(3,595,800	)		2,806,271
Total unrealized gain (loss), net		1,475,665			(3,595,800	)
Commodity price risk management (loss) gain, net	$	(1,087,368	)	$	3,038,361
Commodity price risk management gain (loss), net	$	2,230,057		$	(1,087,368	)

Realized gains recognized in ~~2009~~2010 ofand ~~$2.5~~2009 ~~million~~ are a result of lower natural gas and crude oil ~~commodity~~spot prices at settlement compared to the respective strike price~~. During 2009~~, ~~the~~offset ~~Partnership~~in ~~recorded~~part ~~unrealized~~by ~~derivative losses of $1.7 million on~~ the ~~Partnership’s~~negative ~~CIG~~ basis ~~swaps, as the forward basis~~ differential between NYMEX and CIG ~~continued~~being tonarrower ~~narrow~~than ~~and~~the ~~became~~strike aprice ~~positive differential for two~~ of the ~~last four month~~Partnership’s ~~settlements~~derivative position. During 2010, ~~and~~the ~~unrealized~~Partnership ~~derivative~~recorded ~~losses~~unrealized gains of $01.37 million on the Partnership’s ~~oil~~natural ~~positions,~~gas ~~both~~and ofcrude ~~which~~oil positions that were partially offset by unrealized ~~derivative~~losses ~~gains~~ of $0.52 million on its CIG basis swaps as the ~~Partnership’s~~forward ~~natural~~basis ~~gas~~differential ~~positions~~between NYMEX and CIG had continued to narrow from the prior year.

InDuring ~~periods of rising prices~~2009, the Partnership ~~will~~recorded ~~generally~~unrealized ~~record~~ losses on its ~~derivative~~CIG ~~positions~~basis swaps as ~~fair~~the ~~values~~forward ~~exceed~~basis ~~contract~~differential ~~prices~~between ~~determining~~NYMEX ~~the~~and ~~Partnership’s~~CIG ~~oil~~had ~~and~~continued ~~natural~~to ~~gas~~narrow ~~sales. Conversely,~~from inthe ~~periods~~prior ofyear ~~decreasing~~along ~~prices,~~with unrealized losses on the Partnership’s ~~will~~crude ~~generally~~oil ~~recognize~~positions, offset by unrealized gains on ~~its~~the ~~derivative~~Partnership’s natural gas positions.

~~Commodity~~Natural ~~price~~Gas ~~risk~~and ~~management,~~Crude ~~net~~Oil ~~includes~~Sales ~~realized~~Derivative ~~gains~~Instruments. The ~~and~~Partnership ~~losses~~uses various derivative instruments to manage fluctuations in natural gas and ~~unrealized~~crude ~~changes~~oil prices. The Partnership has in ~~the~~place ~~fair~~a ~~value~~variety of ~~derivative~~floors, ~~instruments~~collars, ~~related~~fixed-price toswaps and basis swaps on a portion of the Partnership’s estimated natural gas and crude oil production. Because the Partnership sells its physical natural gas and crude oil at similar prices to the indexes 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. See Note 43, Fair Value of Financial Instruments, and Note 54, Derivative Financial Instruments, to the ~~accompanying~~Partnership’s financial statements ~~for~~included ~~additional~~in ~~details~~this report on how each derivative type impacts the Partnership’s cash flows and detailed presentation of the Partnership’s derivative ~~financial~~positions ~~instruments~~as of December 31, 2010.

- 21 33-

~~Index~~Table Of Contents

The following table presents the Partnership’s derivative positions in effect as of December 31, ~~2009~~2010.

	Collars						Fixed-Price Swaps				CIG Basis Protection Swaps
Commodity/ Index	Quantity (Gas-Mmbtu)		Weighted Average Contract Price				Quantity (Gas-Mmbtu Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-Mmbtu)		Weighted Average Contract Price			Fair Value at December 31, 2009(1)
Commodity/	Quantity		Weighted Average Contract Price				Quantity (Gas-Mmbtu(1)		Weighted Average Contract		Quantity		Weighted Average Contract			Fair Value at December 31,
			Floors		Ceilings
Index	(Gas-Mmbtu(1))		Floors		Ceilings		Oil-Bbls)		Price		(Gas-Mmbtu(1))		Price			2010(2)
Natural Gas
CIG
1Q 2010		79,983	$	7.50	$	7.50		56,178	$	9.20		-	$	-		$	389,934
01/01 - 03/31/2011		53,565	$	4.75	$	9.45		-	$	-		-	$	-		$	41,587
4Q 2010		35,710		4.75		9.45		-		-		-		-			6,414
2011		53,565		4.75		9.45		-		-		-		-			3,064
NYMEX
2Q 2010		-		-		-		132,765		5.55		127,368		(1.88	)		(182,975	)
01/01 - 03/31/2011		21,022		5.75		8.30		38,758		6.81		59,780		(1.88	)		35,619
3Q 2010		-		-		-		130,629		5.56		124,865		(1.88	)		(210,227	)
04/01 - 06/30/2011		-		-		-		113,252		6.78		113,252		(1.88	)		108,994
4Q 2010		15,514		5.75		8.30		72,654		6.07		85,961		(1.88	)		(118,304	)
07/01 - 09/30/2011		-		-		-		111,525		6.73		111,525		(1.88	)		87,339
2011		21,022		5.75		8.30		371,989		6.77		393,011		(1.88	)		(318,900	)
10/01 - 12/31/2011		-		-		-		108,454		6.78		108,454		(1.88	)		55,623
2012		28,595		6.00		8.27		379,097		6.98		407,691		(1.88	)		~~(302~~175,~~665~~943	)
2013		-		-		-		373,459		7.12		373,459		(1.88	)		~~(262~~156,~~484~~508	)
Total Natural Gas		~~234~~103,~~389~~182						1,~~516~~124,~~771~~545				1,~~512~~174,~~355~~161					~~(996~~661,~~143~~613	)
Oil
Crude Oil
NYMEX
1Q 2010		-		-		-		3,262		92.96		-		-			41,693
01/01 - 03/31/2011		-		-		-		1,476		70.75		-		-			(30,661	)
2Q 2010		-		-		-		3,300		92.96		-		-			36,925
04/01 - 06/30/2011		-		-		-		1,487		70.75		-		-			(32,956	)
3Q 2010		-		-		-		3,336		92.96		-		-			32,933
07/01 - 09/30/2011		-		-		-		1,483		70.75		-		-			(33,528	)
4Q 2010		-		-		-		3,336		92.96		-		-			28,954
10/01 - 12/31/2011		-		-		-		1,503		70.75		-		-			(34,025	)
2011		-		-		-		5,949		70.75		-		-			(89,584	)
Total Crude Oil		-						5,949				-					(131,170	)
Total Oil								19,183									50,921
Total Natural Gas and Crude Oil																$	530,443
Total Natural Gas and Oil																$	(945,222	)

(1) ~~Approximately 52% of the total fair value of the derivative~~ ~~assets~~A ~~and~~standard ~~98%~~unit of ~~liabilities~~measure ~~were~~for ~~measured~~natural ~~using~~gas ~~significant~~(one ~~unobservable~~MMBtu ~~inputs.~~equals ~~See~~one ~~Note 4, Fair Value Measurements, to the accompanying financial statements included in this report~~Mcf).

~~Natural~~(2) As ~~Gas~~of December 31, 2010, approximately 5% of the fair value of the Partnership’s derivative assets and ~~Oil~~all ~~Production~~of ~~Costs~~the Partnership’s derivative liabilities were measured using significant unobservable inputs (Level 3).

Natural ~~gas and oil production costs include production taxes and transportation costs which vary with revenues and production~~Gas, ~~well~~NGLs ~~operating costs charged on a per well basis~~ and ~~other~~Crude ~~direct~~Oil ~~costs~~Production incurred in the production process. As production declines, fixed costs increase as a percentage of total costs resulting in production costs per unit increases. As production is expected to continue to decline, production costs per unit can be expected to increase.Costs

~~Generally,~~Natural ~~natural~~ gas, NGLs and crude oil production costs ~~vary~~include ~~with~~production ~~changes~~taxes inand ~~total~~transportation ~~oil~~costs ~~and~~which ~~natural~~vary ~~gas~~with ~~sales~~revenues and production, ~~volumes. Property~~well ~~and~~operating ~~severance~~costs ~~taxes~~charged ~~are estimates by the Managing General Partner based~~ on ~~rates~~a ~~determined~~per ~~using~~well ~~historical~~basis ~~information. These~~and ~~amounts~~other ~~are~~direct ~~subject~~costs toincurred ~~revision~~in ~~based on actual amounts determined during future filings by~~ the ~~Managing~~production ~~General~~process. ~~Partner~~As ~~with~~production ~~the~~declines, ~~taxing~~fixed ~~authorities. Property~~costs ~~and~~increase ~~severance~~as ~~taxes~~a ~~vary~~percentage ~~directly~~of ~~with~~ total ~~oil and natural gas sales. Transportation~~ costs ~~vary~~resulting ~~directly~~in ~~with~~ production ~~volumes. Fixed monthly well operating~~ costs ~~increase on a~~ per unit ~~basis~~increases. Typically, as production ~~decreases~~is ~~per~~expected ~~the~~to ~~historical~~continue ~~decline~~to ~~curve. In addition~~decline, ~~general~~production ~~oil field services and all other~~ costs ~~vary~~per ~~and~~unit can ~~fluctuate~~be ~~based~~expected onto ~~services~~increase ~~required. These~~in ~~costs~~the ~~include~~future ~~water~~until ~~hauling~~such ~~and~~time ~~disposal,~~as ~~equipment~~the ~~repairs~~Partnership ~~and~~successfully ~~maintenance,~~recompletes ~~snow~~the ~~removal~~Wattenberg ~~and~~Field ~~service rig workovers~~wells.

~~Natural~~Generally, natural gas, NGLs and crude oil production costs ~~were~~vary ~~lower~~with bychanges ~~$0.4~~in ~~million,~~total ornatural ~~22%~~gas, ~~due~~NGLs toand ~~volume-associated~~crude ~~reductions~~oil ofsales $0and production volumes.1 Production ~~million~~taxes inare ~~production~~estimates ~~taxes,~~by ~~natural~~the ~~gas~~Managing ~~transportation~~General ~~and~~Partner ~~lease~~based ~~operating~~on ~~expenses~~tax rates determined using published information. InThese ~~addition~~estimates toare ~~volume-associated~~subject ~~production~~to ~~tax~~revision ~~decreases,~~based ~~lower~~on ~~commodity~~actual ~~valuations~~amounts ~~further~~determined ~~lowered~~during ~~production~~future ~~taxes~~filings by ~~approximately~~the ~~$0.5~~Managing ~~million~~General Partner with the taxing authorities. ~~However~~Production taxes vary directly with total natural gas, ~~lease~~NGLs ~~operating~~and crude oil sales. Transportation costs ~~increased~~vary bydirectly $0with production volumes.2 Fixed ~~million~~monthly ~~due~~well tooperating costs increase on a ~~well~~per ~~site~~unit ~~remediation~~basis ~~required~~as byproduction ~~the~~decreases ~~state~~per ofthe ~~Colorado~~historical ~~that~~decline ~~offset~~curve. In ~~lower~~addition, ~~third-party~~general oil field services ~~costs,~~and ~~whose~~all ~~lowering~~other ~~rates~~costs ~~are~~vary ~~attributable~~and tocan ~~declining~~fluctuate ~~oil~~based ~~field~~on services ~~demand~~required inbut ~~this~~are ~~low-commodity~~expected ~~price~~to ~~environment,~~increase ~~and~~as ~~the~~wells ~~Managing~~age ~~General~~and ~~Partner’s~~require ~~own~~more ~~cost-cutting~~extensive ~~initiatives. Natural~~repair ~~gas~~ and ~~oil~~maintenance. These ~~production~~ costs ~~per~~include ~~Mcfe~~water ~~were~~hauling ~~$1.64~~and ~~during~~disposal, ~~the~~equipment ~~year~~repairs ~~2009~~and ~~compared~~maintenance, tosnow ~~$1.98~~removal ~~for~~and ~~the~~service ~~year~~rig ~~2008~~workovers.

-Changes 22in -natural gas, NGLs and crude oil production expenses. Production and operating costs were lower by approximately $0.1 million, or 6%, due in part, to lower lease operating expenses related to the Managing General Partner’s cost cutting initiatives, which were partially offset by three well workovers and nonrecurring environmental remediation activity expenses of $51,000 that includes a December 31, 2010 accrual of $5,000. As an additional offset, production and operating costs also increased as a result of production taxes increases due to higher commodity valuations and higher 2010 well operations costs due to the increase in the per well operations fee charged by the Managing General Partner, consistent with the terms of the D&O Agreement. Production and operating costs per Mcfe were $1.68 for 2010 compared to $1.64 for 2009.

~~Index~~-34-

~~Direct~~Table ~~Costs~~Of ~~– General and Administrative~~Contents

Direct ~~costs~~Costs−General ~~– 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 2009 by $0.1 million principally due to billings for professional services.Administrative

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 decreased during the 2010 annual period compared to the 2009 annual period, by approximately $0.3 million principally due to reduced fees for professional services.

Depreciation, Depletion and Amortization

Natural gas and crude oil properties. Depreciation, depletion and amortization (DD&A) expense ~~results~~related ~~solely~~to ~~from~~natural ~~the~~gas ~~depreciation, depletion~~ and ~~amortization~~crude ofoil ~~well~~properties ~~equipment~~is ~~and~~directly ~~lease~~related ~~costs.~~to ~~The~~proved ~~Partnership’s~~reserves ~~calculation~~and ofproduction volumes. DD&A expense is primarily based upon year-end proved developed producing ~~natural gas and oil~~ reserves ~~and is determined by these reserves and their associated production volumes~~. ~~For~~The ~~2008,~~pricing ~~the~~measurement ~~Partnership’s~~for ~~natural gas and oil economically producible~~ reserve ~~quantities~~estimations ~~were~~is determined by valuing in-ground natural gas and oil resources, at the price of natural gas and oil as of December 31, 2008. In 2009, the SEC published its final rule regarding the modernization of oil and gas reporting, which changed the valuation price from a ~~December 31 single-day pricing to a price determined by the~~ 12-month average of the first- day- of- the- month price ~~during~~for each month ofin ~~2009~~the period. If ~~valuation~~ prices increase, the estimated volumes of ~~natural~~proved ~~gas and oil~~ reserves will increase, resulting in decreases in the rate of DD&A ~~for~~per ~~each~~unit ~~Mcfe~~of ~~produced~~production. If ~~valuation~~ prices decrease, the estimated volumes of ~~natural~~proved ~~gas and oil~~ reserves will decrease, resulting in increases in the rate of DD&A ~~for~~per ~~each~~unit ~~Mcfe~~of ~~produced~~production.

Changes in DD&A expense. The DD&A expense rate per Mcfe ~~increased~~decreased to $3.8719 ~~for~~during ~~the year ended December 31~~2010, ~~2009,~~ compared to $23.9987 during ~~the same period in 2008~~2009. The ~~variance~~decrease in the per Mcfe rates for ~~2009~~2010 compared to ~~2008~~2009 is ~~partially~~primarily the result of the changing production mix between the Partnership’s Wattenberg and Grand Valley Fields, which have significantly different DD&A rates,. ~~and~~This ~~the~~was ~~overall~~affected ~~production~~by ~~volume~~field-level ~~decline~~depletion ofrate 6%changes ~~which~~due ~~reduced~~to ~~DD&A~~reserve ~~expense~~revisions byat ~~$0.2~~December ~~million~~31, in 2009 compared to ~~the~~December ~~previous~~31, ~~year. Production-related DD&A expense reductions were offset however~~2008, ~~by a $1.0 million increase~~ in ~~DD&A~~which ~~expense during the first three quarters of 2009 as a consequence of lower~~ proved developed producing ~~natural~~downward ~~gas~~revisions ~~and oil reserves reported~~ in the Partnership’s ~~annual~~Grand ~~December~~Valley ~~31,~~Field ~~2008~~were ~~reserve~~partially ~~report~~offset ~~which~~by ~~resulted~~upward inproved ~~higher~~developed ~~DD&A~~producing ~~rates~~revisions in ~~effect~~its ~~through~~Wattenberg ~~September 30, 2009, than during the comparable periods of 2008~~Field. ~~During~~The ~~fourth~~decreased ~~quarter~~DD&A ~~2009~~expense rate, ~~increases~~combined inwith the ~~Partnership’s~~production ~~Wattenberg~~declines ~~Field~~noted ~~proved developed producing natural gas and oil reserves reported~~ in ~~the~~previous ~~December 31~~sections, ~~2009~~resulted ~~annual~~in ~~reserve report, contributed to~~ a decreased DD&A expense ~~reduction~~ of ~~$0.2~~approximately ~~million from the fourth quarter 2008 DD&A expense. Overall, DD&A expense during 2009 increased~~ $0.68 million ~~from that of the previous year. See Supplemental Oil and Gas Information – Unaudited, Net Proved Natural Gas and Oil Reserves~~ for ~~additional~~2010 ~~information~~compared ~~regarding~~to ~~the Partnership’s reserves reported as of December 31,~~ 2009 ~~and 2008~~.

~~Liquidity~~Financial ~~and Capital Resources~~Condition

~~The~~Capital ~~Partnership’s~~Resources ~~primary sources of cash in 2009 were from funds generated from the sale of natural gas~~ and oil production, the net realized gains from the Partnership’s derivative positions and the decrease in “Due from Managing General Partner – Other, Net.” These sources of cash were primarily used to fund the Partnership’s operating cost, general and administrative activities and provide monthly distributions to the Investor Partners and PDC, the Managing General Partner. Fluctuations in the Partnership’s operating cash flow are substantially driven by commodity prices, change in production volumes and realized gains and losses from commodity positions. Commodity prices have historically been volatile and the Partnership manages 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 and oil sales and realized derivative gains and losses. However, the Partnership does not hold derivative instruments for 100% of the Partnership’s expected future production and therefore may still experience significant fluctuations in our cash flows from operations. See Results of Operations for further discussion of the impact of prices and volumes on sales from operations and the impact of derivative activities on the Partnership’s revenues.Liquidity

The Partnership’s ~~future~~primary ~~operations~~sources ~~are~~of ~~expected~~cash tofor beboth ~~conducted~~the ~~with~~2010 ~~available~~and ~~funds~~the ~~and~~2009 ~~revenues~~annual ~~generated~~periods were from ~~oil~~funds ~~and~~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 Investor Partners and PDC, the Managing General Partner. Fluctuations in the Partnership’s operating cash flow are substantially driven by changes in commodity prices, in production volumes and in realized gains (and losses) from commodity positions. ~~Oil~~Commodity prices have historically been volatile and ~~gas~~the ~~production~~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 ~~existing~~natural ~~properties~~gas, ~~are~~NGLs ~~expected~~and tocrude ~~continue~~oil asales ~~gradual~~and ~~decline~~realized ~~over~~natural gas and crude oil derivative gains and losses. However, the ~~remaining~~Partnership ~~life~~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. ~~Therefore~~As of December 31, 2010, the Partnership ~~expects~~had anatural ~~lower~~gas ~~annual~~and ~~level~~crude oil derivative positions in place covering 73% of ~~oil~~expected ~~and~~natural gas production and 35% of expected oil production for 2011, inat ~~the~~an ~~absence~~average price of ~~significant~~$4.82 ~~price~~per ~~increases,~~Mcf ~~lower~~and ~~revenues~~$70.75 per Bbl, respectively. The Partnership’s ~~also~~current ~~expects~~derivative ~~cash~~position ~~flows~~average prices have declined from ~~operations~~the tosignificantly ~~decline~~higher ifaverage commodity ~~prices~~contract ~~remain~~strike atprice ~~current~~ levels orin ~~decrease~~effect induring the ~~future. Under~~2009 ~~these~~comparative ~~circumstances~~period ~~decreased~~which ~~production~~were ~~would~~the ~~have~~result aof ~~material~~contracts ~~negative~~entered ~~impact~~into onduring the high 2008 commodity price market; accordingly, the Partnership’s ~~operations~~anticipates ~~and~~realized ~~may~~gains ~~result~~for inthe ~~reduced~~next ~~cash~~12 ~~distributions~~months to ~~the~~remain ~~Investor~~substantially ~~Partners~~below gains realized in ~~2011~~2010 and ~~beyond~~2009. ~~Future~~See ~~cash~~Results ~~distributions~~of ~~may~~Operations ~~also~~for befurther ~~reduced~~discussion toof ~~fund~~the ~~well~~impact ~~recompletions~~of inprices ~~the~~and ~~Codell~~volumes ~~formation~~on sales from operations and the impact of derivative activities on the ~~Wattenberg~~Partnership’s ~~Field~~revenues.

-The 23Partnership’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 the Managing General Partner and Investor Partners through the remainder of 2011 and beyond, and may substantially reduce or restrict the Partnership’s ability to participate in the refracturing activities which are more fully described in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments−Well Refracturing Plan.

~~Index~~-35-

Table Of Contents

Working Capital

~~Working~~The Partnership’s working capital at December 31, ~~2009~~2010 ~~was~~and ~~$1.0~~2009, ~~million~~remained ~~compared~~substantially tounchanged ~~working~~at ~~capital of~~ $41.30 million ~~at December 31, 2008~~. ~~This~~Changes ~~decrease~~in ofthe ~~$3.3~~components ~~million~~comprising ~~was~~working ~~primarily~~capital ~~due~~include to the following ~~changes in accounts receivable balances~~:

· ~~Natural~~Cash ~~gas~~ and ~~oil~~cash ~~receivables~~equivalents ~~decreased~~increased toby $0.82 million asbetween of December 31, ~~2009,~~2010 ~~from~~and ~~$0.9 million as of~~ December 31, ~~2008~~2009.

· ~~Realized~~Accounts ~~derivative~~receivable ~~gains receivables~~ decreased toby $0.41 million asbetween of December 31, ~~2009,~~2010 ~~from~~and ~~$0.7 million as of~~ December 31, ~~2008~~2009.

· ~~Net~~Realized ~~short-term unrealized~~ derivative gains ~~receivable~~receivables decreased toby $0.03 million asbetween of December 31, ~~2009,~~2010 ~~from~~and ~~$2.1 million as of~~ December 31, ~~2008~~2009.

~~Additionally,~~· ~~during~~Net ~~the~~short-term ~~third~~unrealized ~~quarter~~derivative ~~2009~~gains ~~there was a net reduction of $1.1 million in amounts due from the Managing General Partner as a $1.2 million~~ receivable for over-withheld production taxes related to Partnership production prior to 2007 was collected. In addition, the Partnership settled the obligation for the Colorado Royalty Settlement of approximately $0.1 million with the Managing General Partner. The net cash impact of these transactions increased ~~distributions~~ by $10.12 million ~~during~~between ~~2009. For~~December ~~more information on the Colorado Royalty Settlement see Note 9~~31, ~~Commitments~~2010 and ~~Contingencies~~December to31, ~~the accompanying audited financial statements~~2009.

Working capital, primarily cash and cash equivalents, is expected to increase during 2011 due to cash flows from operations and the Partnership’s anticipated withholding of cash from the Managing General Partner and Investor Partners, on a pro-rata basis, for the initial refracturing activities. This withholding began in the fourth quarter of 2010 with the withholding of $60,000 as of December 31, 2010. Cash will begin to decrease as the funds are utilized in payment of the refracturing activities, currently planned to occur during mid-to-late 2012. Funding for the Well Refracturing Plan will be provided by the withholding of distributable cash flows from the Managing General Partner and Investor Partners on a percentage of Partnership ownership pro-rata basis. Working capital is expected to similarly fluctuate by increasing during periods of Well Refracturing Plan funding and by decreasing during periods when payments are made for completed refracturing.

Cash Flows

Cash Flows From Operating Activities

Net cash provided by operating activities was $3.6 million for 2010 compared to $5.0 million for 2009, a decrease of approximately $1.4 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 $0.8 million, or 24%, accompanied by decreases in natural gas, NGLs and crude oil production costs of $0.1 million, or 6% and direct costs-general and administrative of $0.3 million, or 57%;

A decrease in commodity price risk management realized gains receipts of approximately $1.8 million, or 64% and

A decrease in Due to Managing General Partner-other, net, receipts of approximately $0.7 million, excluding natural gas, NGLs and crude oil sales received from third parties and realized derivative gains.

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Cash Flows From Investing Activities

The Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of ~~oil~~natural gas and ~~gas~~crude oil or environmental protection. These amounts totaled approximately $2954,000 and $3129,000 for ~~2009~~2010 and ~~2008~~2009, respectively. The Partnership received an approximate $108,000 refund from the Managing General Partner during 2009, for an unused drilling ~~advances and an approximate $129,000 Colorado sales tax refund in 2008~~advance.

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in September 2005 and has distributed $4043.14 million through December 31, ~~2009~~2010. The table below presents ~~the~~ cash distributions to the Partnership’s investors. Managing General Partner ~~and~~distributions ~~Investor~~include ~~Partners~~amounts ~~including~~distributed to PDC for its Managing General Partner’s 20% ownership share in the Partnership. Investor Partner distributions ~~relating~~include toamounts ~~limited~~distributed ~~partnership~~to ~~units~~Investor ~~repurchased~~Partners for their 80% ownership share in the ~~periods~~Partnership ~~described~~and asinclude ~~follows:~~amounts distributed to PDC for limited partnership units repurchased.

Year Ended	Managing General Partner Distributions		Investor Partners Distributions		Total Distributions
2010	$	671,224	$	2,684,896	$	3,356,120
2009	$	1,028,859	$	4,115,444	$	5,144,303
2008	$	1,192,834	$	4,771,340	$	5,964,174

~~Investor~~The ~~Partner~~decrease ~~cash~~in total distributions ~~include~~for ~~$44,848~~2010 ~~and~~as ~~$17,685~~compared ~~during~~to ~~the years~~ 2009 ~~and~~is ~~2008,~~primarily ~~respectively,~~due ~~related~~ to ~~equity~~the ~~cash~~significant ~~distributions~~decrease onin ~~Investor~~cash ~~Partner~~flows ~~units~~from ~~repurchased~~operating byactivities ~~the~~during ~~Managing~~these ~~General~~respective ~~Partner~~years.

-Additionally, 24the Partnership began funding for the Well Refracturing Plan during October 2010. As of December 31, 2010, on a pro-rata basis based on percentage of ownership in the Partnership, the Partnership withheld $12,000 and $48,000, respectively, from the Managing General Partner’s and Investor Partners’ share of distributable cash flows. These and subsequent withholdings will provide the funding for planned Wattenberg Field well refracturing costs to be incurred during 2012, and thereafter and are expected to decrease distributions from the 2009 levels for the next several years. For additional information, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments−Well Refracturing Plan.

Index

Cash Flows From Operating Activities

Net cash provided by operating activities was $5.0 million for 2009 compared to $6.0 million for 2008, a decrease of $1.0 million. The decrease in cash provided by operating activities was due primarily to the following:

· A decrease in natural gas and oil sales receipts of $4.7 million, or 59%, accompanied by an increase in direct costs – general and administrative of $0.1 million; and

· An increase in realized commodity price risk management, net of $2.3 million and a decrease in natural gas and oil production costs of $0.4 million, or 22%.

· A reduction in “Due from Managing General Partner – Other, Net,” of $1.1 million in third quarter 2009, due to the Managing General Partner’s $1.2 million payment to the Partnership for over-withheld production taxes and accrued interest thereon related to Partnership production prior to 2007 which was partially offset by the Partnership’s approximately $0.1 million payment to the Managing General Partner for royalty settlement costs. For more information on the Colorado Royalty Settlement see Note 9, Commitments and Contingencies to the accompanying financial statements.

Critical Accounting Policies and Estimates

The Managing General Partner has identified the following policies as critical to business operations and the understanding of the results of the operations of the Partnership. ~~This~~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 the Managing General Partner may use significant judgment in their application; as a result these policies are subject to inherent degree of uncertainty. In applying these policies, the Managing General Partner 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. For a more detailed discussion on the application of these and other accounting policies, see Note 2, Summary of Significant Accounting Policies in the accompanying financial statements. The Partnership's critical accounting policies and estimates are as follows:

~~Revenue Recognition~~-37-

~~Natural~~Table ~~Gas~~Of Sales. Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Natural gas is sold upon delivery 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 contracts’ 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 gas and prevailing supply and demand conditions. As a result, the Partnership’s revenues from the sale of natural gas will decrease if market prices decline and increase if market prices increase. The Partnership believes that the pricing provisions of its natural gas contracts are customary in the industry.Contents

~~The~~Natural ~~Partnership~~Gas ~~currently uses the “Net-Back” method of accounting for transportation arrangements of natural gas sales. The Managing General Partner sells natural gas at the wellhead, collects a price,~~ and ~~recognizes~~Crude ~~revenues~~Oil ~~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.~~Properties

~~Oil~~The ~~Sales. Sales~~Partnership ofaccounts ~~oil~~for ~~are~~its ~~recognized~~natural ~~when~~gas ~~persuasive~~and ~~evidence~~crude ofoil aproperties ~~sales~~under ~~arrangement exists,~~ the ~~oil~~successful isefforts ~~verified~~method asof ~~produced~~accounting. Costs ~~and~~of isproved ~~delivered~~developed ~~from~~producing ~~storage~~properties ~~tanks~~and atdevelopmental ~~well~~dry ~~locations~~hole tocosts aare ~~purchaser,~~capitalized ~~collection~~and ofdepreciated ~~revenue~~or ~~from~~depleted ~~the~~by ~~sale is reasonably assured and~~ the ~~sales~~unit-of-production ~~price~~method isbased ~~determinable. The~~on ~~Partnership~~estimated ~~does~~proved ~~not~~developed ~~refine~~producing ~~any of its oil production~~reserves. ~~The~~Property ~~Partnership’s~~acquisition ~~crude~~costs ~~oil~~are ~~production~~depreciated ~~is sold to purchasers at~~ or ~~near~~depleted on the ~~Partnership’s wells under short~~unit-~~term~~of-production ~~purchase~~method ~~contracts~~based aton ~~prices~~estimated ~~and~~proved ~~in accordance with arrangements that are customary in the oil industry~~reserves.

-Annually, 25the Managing General Partner 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 the Managing General Partner’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.

~~Index~~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. The Partnership recognized no impairment of its natural gas and crude oil properties since inception to December 31, 2010.

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. The Managing General Partner estimates the Partnership’s sales volumes based on the Managing General Partner’s measured volume readings. The Managing General Partner 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. The Partnership’s fair value measurements are estimated pursuant to a fair value hierarchy that requires the Managing General Partner 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 fixed price natural gas swaps and collars.-38-

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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 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 ~~fixed-price~~ 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 Managing General Partner measures fair value of the Partnership’s derivatives based upon quoted market prices, where available. The Managing General Partner’s 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 Partner’s valuation determination also gives consideration to the 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 ~~two investment grade~~ financial institutions as counterparties to its derivative contracts. The Managing General Partner has evaluated the credit risk of the counterparties holding the Partnership’s derivative assets ~~from~~using ~~counterparties~~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 ~~counterparty~~ nonperformance of the Partnership’s counterparties on the fair value of the Partnership’s derivative instruments is ~~not material~~insignificant. ~~As of December 31, 2009, no valuation allowance was recorded.~~ Furthermore, while the Managing General Partner believes these valuation methods are appropriate and consistent with that 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.

- 26 -

Index

Natural Gas and Oil Properties

The Partnership accounts for its oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties and developmental dry hole costs are depreciated or depleted by the unit-of-production method based on estimated proved developed producing natural gas and oil reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved natural gas and oil reserves.

Annually, the Managing General Partner 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 and 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 the Managing General Partner’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 and 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.

The Partnership accounts for the impairment or disposal of long-lived assets, by periodically assessing its proved natural gas and 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 future production based upon estimated prices at which the Partnership reasonably estimates the commodity could be sold. The estimates of future prices may differ from current market prices of oil and natural gas. Downward revisions in estimates to the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs may result in a triggering event and therefore a possible impairment of the Partnership’s oil and natural gas properties. If, when assessing impairment, net capitalized costs exceed undiscounted future net cash flows, impairment is based on estimated fair value utilizing a future discounted cash flow analysis and is measured by the amount by which the net capitalized costs exceed fair value. Although cash flow estimates used by the Partnership 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.

Recent Accounting Standards

See Note 2, Summary of Significant Accounting Policies− to the ~~Partnership’s~~ accompanying financial statements included in this ~~report~~Annual Report, for recently issued and implemented accounting standards.

~~Item 7A. Quantitative and Qualitative Disclosures About Market Risk~~-39-

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not applicable.

~~Item~~ITEM 8. FINANCIAL ~~Financial~~STATEMENTS ~~Statements~~AND ~~and~~SUPPLEMENTARY ~~Supplementary Data~~DATA

The ~~financial~~response ~~statements~~to ~~are~~this ~~attached~~Item tois ~~this~~set ~~Form~~forth ~~10-K~~herein in a separate section of this report, beginning at page F-1.

~~Supplemental~~ITEM ~~financial~~9. ~~information~~CHANGES ~~required~~IN byAND ~~this~~DISAGREEMENTS ~~Item~~WITH ~~can~~ACCOUNTANTS beON ~~found~~ACCOUNTING inAND ~~Item~~FINANCIAL ~~7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of this report.~~DISCLOSURE

~~- 27 -~~None.

~~Index~~ITEM 9A CONTROLS AND PROCEDURES

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A(T). Controls and Procedures

The Partnership has no direct management or officers. The management, officers and other employees that provide services on behalf of the Partnership are employed by the Managing General Partner.

2008 Material Weakness

As discussed in the Management’s Report on Internal Control Over Financial Reporting included in the Partnership’s 2008 Annual Report on Form 10-K, the Partnership did not maintain effective internal controls over financial reporting as of December 31, 2008, over transactions that are directly related to and processed by the Partnership, in that the Partnership failed to maintain sufficient documentation to adequately assess the operating effectiveness of internal control over financial reporting. More specifically, the Partnership’s financial close and reporting narrative failed to adequately describe the process, identify key controls and assess segregation of duties. This material weakness has been remediated as of December 31, 2009.

(a) Evaluation of Disclosure Controls and Procedures

As of December 31, ~~2009~~2010, PDC, as Managing General Partner on behalf of the Partnership, carried out an evaluation, under the supervision and with the participation of the Managing General Partner's management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Partnership's disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). This evaluation considered the various processes carried out under the direction of the Managing General Partner’s Disclosure Committee in an effort to ensure that information required to be disclosed in the SEC reports the Partnership files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the Partnership’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure.

Based upon the evaluation, the Managing General Partner’s Chief Executive Officer and Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were effective as of December 31, ~~2009~~2010.

This 2009 Annual Report on Form 10-K does not include an attestation report of the Partnership’s independent registered public accounting firm regarding internal control over financial reporting pursuant to Item 308T (ab)~~(4) of Regulation S-K.~~ ~~Pursuant to Final Order dated October 19, 2009, temporary Item 308T was extended through December 15, 2010. Accordingly, the Partnership will file the attestation report of the Partnership~~Management’s ~~independent registered public accounting firm regarding internal control with the Partnership’s Annual~~ Report on ~~Form~~Internal ~~10-K~~Control asOver ofFinancial ~~December 31, 2010.~~Reporting

Management of PDC, the Managing General Partner of the Partnership, is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Exchange Act Rules 13a-15(bf) ~~Remediation~~ and 15d-15(f) as a process designed by, or under the supervision of, ~~Material~~the ~~Weakness~~issuer’s principal executive and principal financial officers, or persons performing similar functions, and effected by the issuer’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in ~~Internal~~accordance ~~Control~~with accounting principles generally accepted in the United States of America and includes those policies and procedures that:

~~PDC,~~(1) ~~the~~Pertain ~~Managing~~to ~~General Partner, with participation from~~ the ~~Audit~~maintenance ~~Committee~~ of ~~its~~records ~~Board~~that ofin ~~Directors,~~reasonable ~~addressed~~detail ~~the~~accurately ~~material~~and ~~weakness~~fairly ~~disclosed~~reflect in the ~~Partnership’s~~transactions ~~2008~~and ~~Annual~~dispositions ~~Report~~of ~~on Form 10-K. The Managing General Partner believes that~~ the ~~effective~~assets ~~implementation~~ of ~~changes~~the ~~in internal controls over financial reporting outlined below remediated this known material weakness as of December 31, 2009.~~issuer;

~~The~~(2) ~~Partnership~~Provide ~~made~~reasonable ~~the~~assurance ~~following~~that ~~changes~~transactions inare ~~its~~recorded ~~internal~~as ~~control~~necessary ~~over~~to ~~financial~~permit ~~reporting~~preparation of ~~the~~financial ~~Partnership~~statements ~~(as~~in ~~defined~~accordance with accounting principles generally accepted in ~~Rules~~the ~~13a-15(f)~~United States of America and ~~15d-15(f)~~that receipts and expenditures of the ~~Securities~~issuer ~~Exchange~~are ~~Act~~being made only in accordance with authorizations of ~~1934)~~management ~~during~~and ~~2009.~~directors of the issuer; and

·(3) InProvide ~~the~~reasonable ~~second~~assurance ~~quarter,~~regarding ~~the~~prevention ~~Partnership~~or ~~developed~~timely ~~and~~detection ~~implemented~~of aunauthorized ~~plan~~acquisition, touse ~~improve~~or ~~controls~~disposition over certain key financial statement spreadsheets that support all significant balance sheet and income statement accounts. The Partnership also created and documented a procedural framework to ensure the completeness and accuracy of the ~~Partnership~~issuer’s ~~derivative~~assets ~~activities.~~that ~~Additionally,~~could ~~the~~have ~~Partnership has completed the development of~~ a ~~revised~~material ~~financial~~effect ~~close~~on ~~and reporting narrative that adequately describes~~ the ~~process,~~financial ~~identifies~~statements ~~key controls and assesses segregation~~ of ~~duties~~the issuer.

- 28 40-

~~Index~~Table Of Contents

·Because Inof ~~the~~its ~~third~~inherent ~~quarter~~limitations, ~~the Partnership developed documentation that describes the business processes and identifies key controls for~~ internal control over financial reporting ~~that~~may ~~assisted~~not ~~the~~prevent ~~Managing~~or ~~General~~detect ~~Partner in adequately assessing internal control over financial reporting for the Partnership~~misstatements. ~~In addition~~ Also, ~~the~~projections ~~Partnership~~of ~~developed~~any ~~documentation~~evaluation ~~and~~of ~~procedures~~effectiveness to ~~adequately~~future ~~assess~~periods ~~segregation~~are ofsubject ~~duties. The controls and procedures were tested prior~~ to ~~December 31, 2009. At present,~~ the ~~Partnership~~risk ~~has~~that ~~not~~controls ~~quantified~~may ~~the~~become ~~total~~inadequate ~~cost~~because of ~~this~~changes ~~initiative;~~in ~~however~~conditions, or that the ~~majority~~degree of ~~this~~compliance ~~cost~~with ispolicies ~~expected~~or toprocedures bemay ~~paid by the Managing General Partner~~deteriorate.

Management of the Managing General Partner has assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, 2010, based upon the criteria established in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management of the Managing General Partner concluded that the Partnership maintained effective internal control over financial reporting as of December 31, 2010.

Exchange Act Rules 13a-15(c) and 15d – 15(c) and Section 404 of the Sarbanes-Oxley Act of 2002 require management of the Partnership to conduct an annual evaluation of the Partnership’s internal control over financial reporting and to provide a report on management’s assessment, including a statement as to whether or not internal control over financial reporting is effective. Since the Partnership is neither an accelerated filer nor a large accelerated filer as defined by SEC regulations, the Partnership’s internal control over financial reporting was not subject to attestation by the Partnership’s independent registered public accounting firm. As such, this Form 10-K does not contain an attestation report of the Partnership’s independent registered public accountant regarding internal control over financial reporting.

~~During 2009~~PDC, ~~PDC~~the ~~made~~Managing ~~the~~General ~~following~~Partner, ~~changes~~made inno ~~PDC’s~~changes ~~internal~~during ~~control~~the ~~over~~quarter ~~financial~~ended ~~reporting~~December ~~(as~~31, ~~defined~~2010 in ~~Rules 13a-15(f) and 15d-15(f) of~~ the ~~Securities~~Partnership’s ~~Exchange~~internal ~~Act~~control ofover ~~1934)~~financial reporting that have materially affected or are reasonably likely to materially affect the Partnership’s internal control over financial reporting:.

·ITEM ~~Effective July 1, 2009, as part of PDC’s broader financial reporting system, PDC implemented a new partnership investor distribution accounting module replacing the existing accounting software~~9B. OTHER PDC has taken the necessary steps to monitor and maintain appropriate internal controls during this period of change. These steps included procedures to preserve the integrity of the data converted and a review by the business owners to validate data converted. Additionally, PDC provided training related to the business process changes and the financial reporting system software to individuals using the financial reporting system to carry out their job responsibilities, as well as those who rely on the financial information. PDC anticipates that the implementation of this module will strengthen the overall systems of internal controls due to enhanced automation and integration of related processes. PDC is modifying the design and documentation of internal control process and procedures relating to the new module to supplement and complement existing internal control over financial reporting. The system changes were undertaken to integrate systems and consolidate information and were not undertaken in response to any actual or perceived deficiencies in PDC’s internal control over financial reporting. Testing of the controls related to these new systems was included in the scope of PDC’s assessment of its internal control over financial reporting as of December 31, 2009.INFORMATION

The Managing General Partner continues to evaluate the ongoing effectiveness and sustainability of the changes PDC made in internal control over financial reporting, and as a result of the ongoing evaluation, may identify additional changes to improve internal control over financial reportingNone. Further information regarding the material weakness of the Partnership referenced above may be found in the Partnership’s Annual Report on 10-K for the year ended December 31, 2008 under Item 9A (T), Controls and Procedures − Management’s Report on Internal Control Over Financial Reporting.

~~Item 9B. Other Information~~-41-

~~None~~Table Of Contents

- 29 -

Index

PART III

~~Item~~ITEM 10. ~~Directors~~ DIRECTORS, ~~Executive~~EXECUTIVE ~~Officers~~OFFICERS ~~and~~AND ~~Corporate~~CORPORATE ~~Governance~~GOVERNANCE

The Partnership has no employees of its own and has authorized the Managing General Partner to manage the Partnership’s business through the D&O Agreement. PDC’s directors and executive officers and other key employees receive direct remuneration, compensation or reimbursement solely from PDC, and not the Partnership, with respect to services rendered in their capacity to act on behalf of the Partnership.

Board Management and Risk Oversight

PDC, a publicly-owned Nevada corporation, was organized in 1955. The common stock of PDC is traded on the NASDAQ Global Select Market under the symbol "PETD." The business and affairs of the Partnership are managed by the Managing General Partner through the D&O Agreement, by or under the direction of PDC’s Board of Directors (the “Board”), in accordance with Nevada law and PDC’s byBy-~~laws~~Laws. The directors’ fiduciary duty is to exercise their business judgment in the best interests of PDC’s shareholders, and in that regard, as Managing General Partner, the best interests of the Partnership and other sponsored drilling partnerships. The Board has adopted Corporate Governance Guidelines that govern the structure and functioning of the Board and establish the Board’s policies on a number of corporate governance issues. With respect to the separation of the offices of Chairman and Chief Executive Officer, or CEO, the Board believes it is most prudent to address this issue as a part of its succession planning process and to make a final determination based on the facts and circumstances at the time of the Chairman’s election, annually or as circumstances warrant.

The ~~Board~~Managing ~~has~~General ~~established~~Partner’s ~~the~~Board ~~Planning~~seeks to understand and ~~Finance~~oversee ~~Committee~~critical tobusiness ~~oversee~~risks. Risks ~~the~~are ~~responsibilities~~considered in every business decision, not just through Board oversight of the Managing General Partner’s Risk Management system. The Board ~~related~~realizes, however, that it is not possible to ~~planning~~eliminate all risk, nor is it desirable, and ~~finance~~that ~~with~~appropriate ~~respect~~risk-taking is essential to achieve the Managing General Partner’s objectives. The Board risk ~~assessment~~oversight ~~and~~structure provides that management ~~process~~report ~~that~~on critical business risk issues to the Planning and Finance Committee, which includes in part, an oversight function concerning PDC’s liquidity, operational and credit risk management. In this regard, the Planning and Finance Committee also provides similar risk assessment and management process oversight functions for sponsored drilling program partnerships, which includes the Partnership. Other Board committees, however, are active in managing the risks related to such committee’s oversight areas. For example, the Audit Committee reviews many risks and related controls in areas that it considers fundamental to the integrity and reliability for the PDC’s financial statements, such as counterparty risks and derivative program risks. The Managing General Partner’s Board has established the Audit Committee, including a subcommittee which focuses specifically on financial reporting matters of PDC’s sponsored drilling partnerships, to assist the Board in monitoring not only the integrity of the Managing General Partner’s financial reporting systems and internal controls asbut ~~well~~also as PDC’s legal and regulatory compliance. InThe ~~addition to these two standing committees, the~~ Board has created a Special Committee that has considered, upon Board request, the potential repurchase of certain of the sponsored drilling partnerships, including this Partnership, for which PDC serves as Managing General Partner.

Managing General Partner Duties and Resource Allocation

As the Managing General Partner, PDC actively manages and conducts the business of the Partnership under the authority of the D&O Agreement. PDC’s executive officers are full-time employees who devote the entirety of their daily time to the business and operations of PDC. Included in each executive’s responsibilities to PDC is a time commitment, as may be reasonably required of their expertise, to conduct the primary business affairs of the Partnership that include the following:

· ~~Optimal~~Profitable development and cost-effective production operations of the Partnership’s ~~traditional oil and gas~~ reserves;

· Market-responsive ~~oil~~natural gas and ~~gas~~crude oil marketing and prudent field operations cost management which support ~~predictable~~maximum cash flows; and

· Technology-enhanced compliant Partnership administration including the following: accounting; revenue and cost allocation; cash management; tax and regulatory agency reporting and filing; and Investor ~~Relations~~Partner relations.

~~Although the Partnership has no Code of Ethics, PDC has a Code of Ethics that applies to its senior executive officers. The Code of Ethics is posted on PDC’s website at www.petd.com.~~-42-

~~Since~~Table ~~1969,~~Of PDC has been engaged in the business of exploring for, developing and producing oil and gas primarily in the Appalachian and Michigan Basins and Rocky Mountain Region. Approximately 36% of the 5,000 oil and natural gas wells owned by PDC are located in the DJ and Piceance Basins where the Partnership operates. PDC’s significant operational capacity in these two areas, particularly in the DJ Basin where PDC is one of the top 5 operators among 170 who control 90% of the basin’s acreage, enables it to be an effective and low cost operator in both basins. PDC began sponsoring drilling partnerships in 1984 and sponsored one or more every year through 2007. PDC did not offer new drilling partnerships in 2008 or 2009, and has no plans to make any offers throughout 2010 or beyond. In October 2009, PDC announced the creation of a new joint venture with an unrelated third-party to develop PDC’s Marcellus Shale acreage and shallow Devonian assets in the Appalachian Basin. Because PDC must divide its managerial and technical staff’s attention directing the operation of PDC’s own corporate interests, the affairs of the 32 other limited partnerships for which PDC services as operator and Managing General Partner and business start-up of the new Appalachian Basin joint venture, the Partnership will not receive PDC's full attention and efforts at all times. However, the Board believes that the organization continues to dedicate sufficient time, attention and expertise to the Partnership to appropriately manage the affairs of the Partnership.Contents

-Although 30the -Partnership has not adopted a formal Code of Ethics, the Managing General Partner, has implemented a Code of Business Conduct and Ethics, as amended (“the Code of Conduct”) that applies to all Directors, officers, employees, agents and representatives of the Managing General Partner and consultants. The Managing General Partner’s principal executive officer, principal financial officer and principal accounting officer are subject to additional specific provisions under the Code of Conduct. The Managing General Partner’s Code of Conduct is posted on PDC’s website at www.petd.com.

~~Index~~The Corporate Governance section of the Managing General Partner’s internet site contains additional information, including By-Laws, written charters for each Board committee and Board corporate governance guidelines. PDC's internet address is www.petd.com. PDC will make available to Investor Partners audited financial statements of PDC for the most recent fiscal year and unaudited financial statements for interim periods. PDC also posts these audited financial statements filed with the SEC, on its internet site.

PDC will make available to Investor Partners audited financial statements of PDC for the most recent fiscal year and unaudited financial statements for interim periods. PDC's internet address is www.petd.com. PDC posts on its internet web site its periodic and current reports and other information, including its audited financial statements which it files with the SEC, as well as various charters and other corporate governance information.-43-

~~Petroleum~~Table ~~Development~~Of ~~Corporation~~Contents

~~The~~Petroleum ~~executive~~Development ~~officers~~Corporation ~~and~~(dba ~~directors of~~ PDC, ~~their principal occupations for the past five years and additional information is presented below:~~Energy)

Name	Age	Positions and Offices Held	Director Since	Directorship Term Expires
Richard W. McCullough	58	Chairman and Chief Executive Officer	2007	2010
Gysle R. Shellum	58	Chief Financial Officer	-	-
R. Scott Meyers	35	Chief Accounting Officer	-	-
Daniel W. Amidon	49	General Counsel and Secretary	-	-
Barton R. Brookman, Jr.	47	Senior Vice President Exploration and Production	-	-
Lance Lauck	47	Senior Vice President Business Development	-	-
Vincent F. D'Annunzio	57	Director	1989	2010
Jeffrey C. Swoveland	55	Director	1991	2011
Kimberly Luff Wakim	51	Director	2003	2012
David C. Parke	43	Director	2003	2011
Anthony J. Crisafio	57	Director	2006	2012
Joseph E. Casabona	66	Director	2007	2011
Larry F. Mazza	49	Director	2007	2010
James M. Trimble	61	Director	2009	2010

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

- 31 -

Name	Age	Positions and Offices Held	Director Since	Directorship Term Expires

Richard W McCullough	59	Chairman and Chief Executive Officer	2007	2013

Gysle R. Shellum	59	Chief Financial Officer	-	-

R. Scott Meyers	36	Chief Accounting Officer	-	-

Barton R. Brookman, Jr.	48	Senior Vice President Exploration and Production	-	-

Daniel W. Amidon	50	General Counsel and Secretary	-	-

Lance Lauck	48	Senior Vice President Business Development	-	-

Joseph E. Casabona	67	Director	2007	2011

Anthony J. Crisafio	58	Director	2006	2012

Larry F. Mazza	50	Director	2007	2013

David C. Parke	44	Director	2003	2011

Jeffrey C. Swoveland	56	Director	1991	2011

James M. Trimble	62	Director	2009	2013

Kimberly Luff Wakim	52	Director	2003	2012

~~Index~~Richard W. McCullough was appointed Chief Executive Officer of the Company in June 2008 and Chairman of PDC’s Board of Directors in November 2008. From November 2006 until November 2008, he served as the Chief Financial Officer of the Company. Prior to joining PDC, Mr. McCullough served from July 2005 to November 2006 as an energy consultant. From January 2004 to July 2005, he was President and Chief Executive Officer of Gasource, LLC, a marketer of long-term, natural gas supplies in Dallas, Texas. From 2001 to 2003, Mr.McCullough served as an investment banker with J.P. Morgan Securities, Atlanta, Georgia, in the public finance utility group supporting bankers nationally in all natural gas matters. Additionally, Mr.McCullough has held senior positions with Progress Energy, Deloitte and Touche, and the Municipal Gas Authority of Georgia. He holds BS and MS degrees from the University of Southern Mississippi and was a practicing Certified Public Accountant for eight years. Mr. McCullough serves as Chairman of the Executive Committee and serves on the Planning and Finance Committee.

~~Richard~~Gysle WR. ~~McCullough~~Shellum was appointed Chief ~~Executive~~Financial Officer in ~~June~~ 2008 ~~and Chairman in November 2008~~. ~~Mr.~~ ~~McCullough~~Prior ~~also~~to ~~served~~joining ~~PDC~~the asCompany, ~~President since March 2008.~~ Mr.Shellum ~~McCullough~~ served as ~~Chief~~Vice ~~Financial~~President, ~~Officer~~Finance ~~from~~and ~~November~~Special ~~2006~~Projects ~~until~~of ~~November~~Crosstex ~~2008~~Energy, L. ~~Prior~~P., ~~to joining PDC~~Dallas, Texas. Mr.Shellum ~~McCullough~~ served asin anthis ~~energy~~capacity ~~consultant~~ from ~~July~~September ~~2005~~2004 tothrough ~~November~~September ~~2006~~2008. From ~~January~~March ~~2004~~2001 tountil ~~July~~September ~~2005~~2004, Mr. Shellum ~~McCullough~~ served as ~~President~~a ~~and~~consultant ~~Chief~~to ~~Executive~~Value ~~Officer~~Capital, ofa ~~Gasource,~~private ~~LLC,~~consulting firm in Dallas, Texas, awhere ~~marketer~~he ofworked ~~long-term,~~on ~~natural~~various ~~gas supplies. From 2001 to 2003~~projects, ~~Mr.~~including ~~McCullough~~corporate ~~served~~finance asand anSarbanes-Oxley ~~investment~~Act ~~banker~~compliance. ~~with~~Crosstex JEnergy, L.P. ~~Morgan~~is ~~Securities,~~a ~~Atlanta,~~publicly ~~Georgia,~~traded ~~and~~Delaware ~~served~~limited inpartnership ~~the~~whose ~~public~~securities ~~finance~~are ~~utility~~listed ~~group~~on ~~supporting~~the ~~bankers~~NASDAQ ~~nationally~~Global inSelect ~~all~~Market ~~natural~~and ~~gas~~is ~~matters. Additionally,~~an ~~Mr.~~independent ~~McCullough~~midstream ~~has~~energy ~~held~~company ~~senior~~engaged ~~positions~~in ~~with~~the ~~Progress Energy~~gathering, ~~Deloitte and Touche~~transmission, ~~and the Municipal Gas Authority of Georgia. Mr. McCullough~~treating, aprocessing ~~CPA,~~and ~~was~~marketing ~~a practicing certified public accountant for 8 years. Mr. McCullough serves as Chairman~~ of ~~the~~natural ~~Executive~~gas ~~Committee~~ and ~~serves~~natural ongas ~~the Planning and Finance Committee~~liquids.

Gysle R. Shellum was appointed Chief Financial Officer effective November 11, 2008. Prior to joining PDC, 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. Prior thereto from March 2001 until September 2004, Mr. Shellum served as a consultant to Value Capital, a private consulting firm in Dallas, 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.44-

Table Of Contents

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.

~~Barton~~Lance ~~R. Brookman, Jr.~~ Lauck was appointed Senior Vice President ~~Exploration~~Business ~~and~~Development ~~Production~~ in ~~March~~August ~~2008~~2009. Previously Mr. Lauck ~~Brookman~~ served as Vice President - ~~Exploration~~Acquisitions and ~~Production~~Business ~~since~~Development ~~joining~~for ~~PDC~~Quantum inResources ~~July~~Management ~~2005. Prior~~LLC tofrom ~~joining~~2006 - ~~PDC, Mr~~2009. ~~Brookman~~From ~~worked~~1988 ~~for~~until ~~Patina~~2006, ~~Oil~~he ~~and~~held ~~Gas~~various ~~and~~management ~~its~~positions ~~predecessor~~at ~~Snyder~~Anadarko ~~Oil~~Petroleum ~~for~~Corporation ~~17 years~~ in athe ~~series~~areas of ~~positions~~acquisitions ofand ~~increasing responsibility~~divestitures, ~~ending~~corporate ~~his~~mergers ~~service~~and asbusiness ~~Vice President of Operations of Patina~~development.

~~Lance~~Joseph ~~Lauck was~~E. ~~appointed~~Casabona ~~Senior~~served as Executive Vice President ~~Business~~and ~~Development~~member onof ~~August~~the ~~31,~~Board ~~2009. Prior~~of toDirectors ~~joining~~of ~~PDC,~~Denver-based ~~Mr.~~Energy ~~Lauck~~Corporation ~~served~~of asAmerica, ~~Vice~~a ~~President~~natural ~~Acquisitions~~gas exploration and ~~Business~~development ~~Development~~company, ~~with~~from ~~Quantum~~1985 ~~Resources~~until ~~Management,~~his ~~LLC~~retirement ~~based~~ in ~~Denver~~May ~~Colorado~~2007. ~~Beginning~~ ~~in June 2006,~~ Mr. Casabona’s ~~Lauck~~responsibilities ~~was~~included ~~responsible~~strategic ~~for~~planning ~~valuation~~as ~~and~~well ~~acquisition~~as ofexecutive ~~oil~~oversight ~~and~~of ~~gas~~drilling ~~exploration~~operations ~~and~~in ~~production~~the ~~properties~~continental U. ~~Prior~~S. toand ~~his~~internationally. ~~employment~~From at2008 ~~Quantum~~through ~~Resources~~2010, Mr. Casabona ~~Lauck~~served ~~was~~as ~~employed~~Chief byExecutive ~~Anadarko~~Officer ~~Petroleum~~of ~~Corporation~~Paramax ~~from~~Resources ~~1988~~Ltd, toa ~~2006~~junior public Canadian oil & gas company (PMXRF) engaged in ~~The~~the ~~Woodlands,~~business ~~Texas. Mr.~~of ~~Lauck~~acquiring ~~served~~and ~~Anadarko~~exploration of oil and gas prospects, primarily in ~~various~~Canada ~~capacities~~and ~~beginning~~Idaho. Mr. Casabona serves as aChairman ~~Senior~~of ~~Production~~the ~~Engineer~~Planning and ~~exited~~Finance asCommittee ~~General~~and ~~Manager,~~serves ~~Corporate~~on ~~Development~~the Audit Committee.

~~Vincent~~Anthony FJ. ~~D’Annunzio~~Crisafio, a Certified Public Accountant, has served as ~~president~~an ofindependent ~~Beverage~~business ~~Distributors~~consultant for more than fifteen years, ~~Inc.~~providing ~~located~~financial and operational advice to businesses in ~~Clarksburg,~~a ~~West~~variety ~~Virginia~~of ~~since~~industries ~~1985~~and stages of development. ~~Mr.~~ ~~D’Annunzio~~He also serves as ~~Chairman~~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 ~~Nominating~~Chief Operating Officer, Treasurer and ~~Governance~~member ~~Committee~~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 onas the ~~Executive~~Chairman of the Audit Committee and serves on the Compensation Committee.

~~Jeffrey~~Larry CF. ~~Swoveland~~Mazza ~~has~~is ~~served~~President asand Chief ~~Operating~~Executive Officer of ~~ReGear~~MVB Bank, Inc. ~~(previously~~in ~~named Coventina Healthcare Enterprises)~~Fairmont, aWest ~~medical~~Virginia. ~~device~~He ~~company~~has ~~that~~been ~~develops~~Chief ~~and~~Executive ~~markets~~Officer ~~products~~since ~~which~~March ~~reduce~~2005, ~~pain~~ and ~~increase~~added the ~~rate~~duties of ~~healing~~President ~~through~~in ~~therapeutic,~~January ~~deep~~of ~~tissue~~2009. ~~heating,~~Prior ~~since~~to ~~May 2007. Previously~~2005, Mr. Mazza ~~Swoveland~~ served as ~~Chief~~Senior ~~Financial~~Vice ~~Officer~~President ofRetail ~~Body~~Banking ~~Media,~~for ~~Inc.,~~BB&T aand ~~life-science~~its ~~company~~predecessors ~~specializing~~ in ~~the~~West ~~design~~Virginia, ~~and~~where ~~development~~he ofwas ~~wearable~~employed ~~body monitoring products and services,~~ from ~~September~~June ~~2000~~1986 to ~~May~~March ~~2007~~2005. ~~Prior~~ ~~thereto,~~A ~~Mr.~~Certified ~~Swoveland~~Public ~~held~~Accountant ~~various~~for ~~positions~~26 years, ~~including~~Mr. Mazza ~~Vice-President~~also ofwas ~~Finance,~~previously ~~Treasurer~~an ~~and~~auditor ~~interim Chief Financial Officer~~ with ~~Equitable Resources, Inc~~KPMG., ~~a diversified natural gas company, from 1994 to September 2000.~~ Mr.Mazza ~~Swoveland~~ serves ason ~~a member of~~ the ~~Board~~Nominating ~~of Directors of Linn Energy, LLC, a public, independent natural gas~~ and ~~oil~~Governance ~~company. Mr.~~Committee ~~Swoveland serves as Presiding Independent Director,~~ and ~~serves on~~ the ~~Audit~~Compensation Committee~~, the Planning and Finance Committee and Executive Committee~~.

- 32 -

Index

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. Ms. Wakim has practiced law with Thorp, Reed & Armstrong LLP since 1990. Ms. Wakim serves as Chairman of the Compensation Committee and serves on the Audit Committee and the Nominating and Governance Committee.

David C. Parke is a Managing Director in the investment banking group of Boenning & Scattergood, Inc., West Conshohocken, Pennsylvania, 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.

Anthony J. Crisafio, a Certified Public Accountant, serves as an independent business consultant providing financial and operational advice to businesses and has done so since 1995. Additionally, Mr. Crisafio has served as the Chief Operating Officer of Cinema World, Inc. from 1989 until 1993 and was a partner with Ernst & Young from 1986 until 1989. Mr. Crisafio serves as the Chairman of the Audit Committee and serves on the Compensation Committee.-45-

~~Joseph~~Table E.Of 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 to his retirement in May 2007. Mr. Casabona’s responsibilities included strategic planning as well as executive oversight of the drilling operations in the continental United States and internationally. In 2008 Mr. Casabona assumed the title of 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.Contents

~~Larry~~Jeffrey FC. ~~Mazza~~Swoveland is President and Chief Executive Officer of ~~MVB~~ReGear ~~Financial~~Life ~~Corporation~~Sciences, Inc. in ~~Fairmont~~Pittsburgh, ~~West~~Pennsylvania ~~Virginia~~(previously named Coventina Healthcare Enterprises), which develops and markets medical device products, where he was previously Chief Operating Officer. From 2000 until 2007, Mr HeSwoveland ~~has~~served ~~been~~as Chief ~~Executive~~Financial Officer ~~since~~of ~~March~~Body ~~2005~~Media, ~~and~~Inc., ~~added~~a life-science company specializing in the ~~duties~~design and development of ~~President~~wearable inbody ~~January~~monitoring ofproducts ~~2009~~and services. Prior ~~to such position~~thereto, Mr. Swoveland ~~Mazza~~held ~~served~~various aspositions, ~~Senior~~including Vice -President ~~Retail~~of ~~Banking~~Finance, ~~Manager~~Treasurer &and ~~President~~interim &Chief ~~CEO~~Financial ~~for~~Officer ~~BB&T~~with ~~and~~Equitable ~~its~~Resources, ~~predecessors~~Inc., ina ~~West~~diversified ~~Virginia~~natural gas company, ~~where~~from he1994 ~~was~~to ~~employed~~September ~~from~~2000. ~~June~~Mr. Swoveland ~~1986~~serves toas ~~March~~a ~~2005~~member of the Board of Directors of Linn Energy, LLC, a public, independent natural gas and oil company. Mr. ~~Mazza~~Swoveland serves as Presiding Independent Director, and serves on the ~~Nominating~~Audit Committee, the Planning and ~~Governance~~Finance Committee and ~~the~~Executive ~~Compensation~~ Committee.

James M. Trimble ~~serves~~has served as Managing Director ~~and Chief Executive Officer~~ of ~~the parent and US subsidiaries of~~ Grand Gulf Energy, Limited (ASX:GGE), a public company traded on the Australian Exchange, since August 2006. In January 2005, Mr. Trimble founded and has since served as President and Chief Executive Officer of the U.S. subsidiary Grand Gulf Energy Company LLC, an ~~Exploration~~exploration and ~~Development~~development company focused primarily on drilling in mature basins in Texas, Louisiana, and Oklahoma. ~~Prior~~ toFrom ~~founding~~2000 ~~Grand~~through ~~Gulf Energy~~2004, Mr. Trimble ~~served~~was ~~as President,~~ Chief Executive Officer ~~and Chairman~~ of ~~the~~Elysium ~~Board~~Energy ofand ~~TexCal~~then Tex-Cal Energy LLC, ~~from~~both ~~June~~were ~~2002~~privately ~~through~~held ~~December~~oil ~~2004. From~~and ~~July~~gas ~~2000~~companies tothat ~~December~~he ~~2001,~~was ~~Mr.~~brought ~~Trimble~~in ~~was~~to ~~President~~take ~~and~~through atroubled ~~member~~workout ofsolutions. ~~the~~Prior ~~Board~~to ofthis, ~~Directors~~he was Senior Vice President of ~~Elysium~~Exploration ~~Energy~~and ~~L.L.C.,~~Production anfor ~~exploration~~Cabot Oil and ~~production~~Gas ~~company~~(NYSE:COG). From ~~1983~~November to2002 ~~2000~~until May 2006, he also served as ~~Senior~~a ~~Vice~~Director ~~President~~of –Blue ~~Exploration~~Dolphin ~~and~~Energy, ~~Production~~an ofindependent ~~Cabot~~oil ~~Oil~~ and ~~Gas~~gas ~~Company,~~company awith ~~publicly~~operations ~~held,~~in ~~mid-sized~~the ~~exploration~~Gulf ~~and~~of ~~production company~~Mexico. Mr. Trimble serves on the Planning and Finance Committee and the Compensation Committee.

~~The~~Kimberly ~~Audit~~Luff ~~Committee~~Wakim, ofan ~~the~~attorney ~~Board~~and ofa ~~Directors~~Certified Public Accountant, is ~~comprised~~a ofPartner ~~Directors~~with ~~Swoveland,~~the ~~Crisafio~~Pittsburgh, ~~Wakim~~Pennsylvania ~~and~~law ~~Casabona.~~firm Thorp, Reed ~~The~~& ~~Board~~Armstrong ~~has~~LLP, ~~determined~~where ~~that~~she serves as a member of the ~~Audit~~Executive Committee and is ~~comprised~~the ~~entirely~~Practice ofGroup ~~independent~~Leader ~~directors~~for asthe ~~defined~~Bankruptcy byand ~~the~~Financial ~~NASDAQ~~Restructuring ~~rule~~Practice ~~4200(a)~~Group. Ms. Wakim has practiced law with Thorp, Reed & Armstrong LLP since 1990. Ms.Wakim was previously an auditor with Main Hurdman (15now KPMG) and was Assistant Controller for PDC from 1982 to 1985. ~~Anthony~~ JShe has been a member of AICPA and the West Virginia Society of CPAs for more than fifteen years. ~~Crisafio~~Ms. ~~chairs~~Wakim serves as Chairman of the ~~Audit~~Compensation Committee~~. All~~ ~~audit~~and ~~committee~~serves ~~members~~on ~~qualify~~the asAudit ~~audit~~Committee ~~committee~~and ~~financial~~the ~~experts~~Nominating and Governance Committee.

-Audit ~~33 -~~Committee

~~Index~~The Audit Committee is composed entirely of persons whom the Board 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 Audit Committee; other members are Directors Wakim, Casabona and Swoveland. The Board 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.

~~Item~~ITEM 11. EXECUTIVE ~~Executive Compensation~~COMPENSATION

The Partnership does not have any ~~directors~~employees or executives of its own. None of PDC's ~~directors~~officers or ~~executive~~directors ~~officers~~ receive any direct remuneration, compensation or reimbursement from the Partnership. These persons receive compensation solely from PDC. ~~None~~The ofManaging ~~PDC’s~~General ~~compensation~~Partner ~~policies~~does ~~and~~not ~~practices~~believe that ~~are~~PDC’s ~~available~~executive toand ~~key~~non-executive ~~employees~~compensation structure, ~~executive~~available to officers or directors who act on behalf of the Partnership, ~~are~~is reasonably likely to have a ~~material~~materially adverse effect on the Partnership’s operations or conduct of PDC when carrying out duties and responsibilities to the Partnership, as Managing General Partner under the Agreement, or as operator under the D&O Agreement. The management fee and other amounts paid to the Managing General Partner by the Partnership are not used to directly compensate or reimburse PDC’s officers or directors. ~~For~~ No ~~more~~management ~~information~~fee onwas paid to PDC in 2010 or 2009 as the Partnership’s ~~compensation~~is not required to pay a management fee other than a one-time fee paid in the initial year of formation per the Agreement. The Partnership pays a monthly fee for each producing well based upon competitive industry rates for operations and field supervision and $75 per well per month for Partnership related general and administrative expenses that include accounting, engineering and management of the Partnership by the Managing General Partner,. See ~~see~~ Item 13, Certain Relationships and Related Transactions, and Director Independence, ~~below~~for a discussion of compensation paid by the Partnership to the Managing General Partner.

-46-

Table Of Contents

Compensation Committee Interlocks and Insider Participation

There are no Compensation Committee interlocks.

~~Item~~ITEM 12. ~~Security~~SECURITY ~~Ownership~~OWNERSHIP ofOF ~~Certain~~CERTAIN ~~Beneficial~~BENEFICIAL ~~Owners~~OWNERS ~~and~~AND ~~Management~~MANAGEMENT ~~and~~AND ~~Related~~RELATED ~~StockholderMatters~~STOCKHOLDER MATTERS

The following table presents information as of December 31, ~~2009~~2010 concerning the Managing General Partner’s interest in the Partnership and other persons known by the Partnership to own beneficially more than 5% of the interests in the Partnership. Each partner exercises sole voting and investing power with respect to the interest beneficially owned.

	Limited Partnership Units
Person or Group	Number of Units Outstanding Which Represent 80% of Total Partnership Interests (1)		Number of Units Beneficially Owned		Percentage of Total Units Outstanding			Percentage of Total Partnership Interests Beneficially Owned
		1,996.87
Petroleum Development Corporation (2) (3) (4)		-		23.75		1.19	%		0.95	%
Petroleum Development Corporation (2) (3) (4) (5)		-		32.21		1.61	%		1.29	%
Investor Partners beneficially owning 5% or more, of limited partner interests		-		-		-			-
Petroleum Development Corporation (2), Managing General Partner		-		-		-			20.00	%

(1) Additional general partner units were converted to limited partner interests at the completion of drilling activities. ~~For more information on the Partnership’s unit conversion, see Item 1, Business−General.~~

(2) Petroleum Development Corporation (dba PDC Energy), 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) The Percentage of “Total Partnership Interests Beneficially Owned” by PDC with respect to its limited partnership units repurchased, is determined by multiplying the percentage of limited partnership units repurchased by PDC to total limited partnership units, by the limited partners’ percentage ownership in the Partnership. [(2332.7521 units/1,996.87 units)*80% limited partnership ownership]

~~Item~~(5) ~~13.~~In ~~Certain~~addition ~~Relationships~~to ~~and~~this ~~Related~~ownership ~~Transactions~~percentage of limited partnership interest, ~~and~~Petroleum ~~Director~~Development ~~Independence~~Corporation (dba PDC Energy) owns a Managing General Partner interest of 20%.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Compensation to the Managing General Partner and Affiliates

The Managing General Partner transacts all of the Partnership’s business on behalf of the Partnership. 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, 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.

- 34 47-

~~Index~~Table Of Contents

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 ~~natural gas and oil~~ reserves at least annually and monitor individual well performance against expectations; and

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

~~PDC~~Salary ~~retains drilling subcontractors, completion subcontractors~~ and aemployment ~~variety~~benefit ofcosts ~~other~~for ~~subcontractors in~~ the ~~performance~~above ofspecialized ~~the work of drilling contract wells. In addition to technical management, PDC may provide~~ services, atare ~~competitive~~covered ~~rates,~~by ~~from~~the ~~PDC-owned~~monthly ~~service~~fees ~~rigs,~~paid ato ~~water~~the ~~truck,~~Managing ~~steel~~General ~~tanks~~Partner ~~used~~as ~~temporarily~~more onfully ~~the~~described ~~well~~in ~~location during~~ the ~~drilling~~preceding ~~and~~Item ~~completion of a well~~11, ~~roustabouts~~Executive ~~and other assorted small equipment and services~~Compensation. A roustabout is an oil and natural gas 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.

~~See~~PDC ~~Note~~procures 3,services ~~Transactions~~on ~~with~~behalf ~~Managing~~of ~~General~~the ~~Partner~~Partnership for costs and ~~Affiliates~~expenses related to the ~~accompanying~~purchase ~~financial~~or ~~statements~~repairs of equipment, ~~for~~materials, ~~information~~third-party ~~regarding~~services, ~~compensation~~brine todisposal and ~~transactions~~the ~~with~~rebuilding of access roads. These are charged at the ~~Managing~~invoice ~~General~~cost ~~Partner~~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 ~~affiliates~~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.

See Note 9, Transactions with Managing General Partner and Affiliates−Ongoing Partnership Business and Operations to the accompanying financial statements, for information regarding compensation to and transactions with the Managing General Partner and affiliates.

Related Party Transaction Policies and Approval

The Agreement and the D&O Agreement with Petroleum Development Corporation (dba PDC Energy) govern related party transactions, including those described above. The Partnership does not have any written policies or procedures for the review, approval or ratification of transactions with related persons outside of the referenced agreements.

Other Agreements and Arrangements

Executive officers of the Managing General Partner were eligible to invest in an executive drilling program, as approved by the Board of Directors. These executive officers profited from their participation in the executive drilling program because they invested in wells at cost and did not pay drilling compensation, management fees or broker commissions and therefore obtained an interest in the wells at a reduced price than that which was charged to the investing partners in a Partnership. Investor partners participating in drilling through a partnership were generally charged a profit or markup above the cost of the wells, management fees and commissions at rates which are generally similar to those for this Partnership outlined in Note 3, Transactions with Managing General Partner and Affiliates to the accompanying financial statements.

Through the executive drilling program, certain former executive officers of PDC invested in the wells developed by PDC in which the Partnership invested. The executive program allowed PDC to sell working interests to PDC executive officers in the wells that PDC developed for the Partnership. Participating officers thereby owned parallel undivided working interests in all of the wells that the Partnership has invested in. Prior to the funding of the Partnership, each executive officer who chose to participate in the executive program advised PDC of the dollar amount of his investment participation, and thereby acquired a working interest in the wells in which the Partnership acquired a working interest, the acquired working interest being parallel to the working interest of the Partnership and the investor partners. The officers’ percentage in certain wells is proportionate to the Partnership’s working interest among all of the Partnership’s wells based upon the officers’ investment amount. PDC had the option to sell working interests in these wells to other parties unaffiliated with PDC prior to the funding of the Partnership. The aggregate ownership percentage of these former executive officers ranges from 0.17% to 0.19% in all of the wells drilled by the Partnership. The Board believed that having the executive officers invest in wells with PDC and other investor partners helped to create a commonality of interests much like share ownership creates a commonality of interests between the shareholders and executive officers. As of December 31, 2009, no current executive officer of the Managing General Partner owns any beneficial interest in the Partnership.

- 35 -

Index

Director Independence

The Partnership has no directors. The Partnership is managed by the Managing General Partner. See Item 10, Directors, Executive Officers and Corporate Governance.

~~Item 14. Principal Accountant Fees and Services~~-48-

Table Of Contents

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table presents amounts charged by the Partnership’s independent registered public accounting firm, PricewaterhouseCoopers LLP (“PwC”) for the years described:

	Year Ended December 31,
Type of Service	~~2009~~2010		~~2008~~2009
Audit Fees (1)	$	~~185~~140,000	$	~~264~~185,000
Tax Fees (2)		~~6,000~~-		166,000
Total fees	$	~~191~~140,000	$	~~280~~191,000

(1) Audit fees consist of professional service fees billed for the audit of the Partnership’s annual financial statements which accompany the Partnership’s Annual Report on Form 10-K, including reviews of the Partnership’s quarterly condensed interim financial statements which accompany ~~the~~this ~~Partnership’s Quarterly reports on Form 10-Q~~report.

(2) Tax fees consist primarily of professional services fees ~~billed~~for tax compliance for assistance with preparation of the Partnership’s annual IRS Form 1065 and individual partners’ Schedule K-1.

Audit Committee Pre-Approval Policies and Procedures

The Sarbanes-Oxley Act of 2002 requires that all services provided to the Partnership by its independent registered public accounting firm be subject to pre-approval by the Audit Committee or authorized members of the Committee. The Partnership has no Audit Committee. The Audit Committee of PDC, as Managing General Partner, has adopted policies and procedures for pre-approval of all audit services and non-audit services to be provided by the Partnership's independent registered public accounting firm. Services necessary to conduct the annual audit must be pre-approved by the Audit Committee annually at a meeting. Permissible non-audit services to be performed by the independent registered public accounting firm may also be approved on an annual basis by the Audit Committee if they are of a recurring nature. Permissible non-audit services to be conducted by the independent registered public accounting firm, which are not eligible for annual pre-approval, must be pre-approved individually by the full Audit Committee or by an authorized Audit Committee member. Actual fees incurred for all services performed by the independent registered public accounting firm will be reported to the Audit Committee after the services are fully performed. The duties of the Committee are described in the Audit Committee Charter, which is available at the Managing General Partner, PDC’s, website under Corporate Governance.

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~~Index~~Table Of Contents

PART IV

~~Item~~ITEM 15. ~~Exhibits~~ EXHIBITS, ~~Financial~~FINANCIAL ~~Statement~~STATEMENT ~~Schedules~~SCHEDULES

(a) The index to Financial Statements is located on page F-1.

(b) Exhibits index.

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith
3.1	Limited Partnership Agreement (filed by PDC as Managing General Partner for PDC 2004-2006 Drilling Program)	S-1 Post-Effective Amend 2	333-111260	Appendix A	06/29/2005
2.1	Agreement and Plan of Merger by and among PDC, DP 2004 Merger Sub, LLC and PDC 2005-A Limited Partnership	8-K	000-51309	2.1	11/22/2010
3.2	Certificate of limited partnership which reflects the organization of the Partnership under West Virginia law	10-K	000-51309	3.2	02/26/2009
3.1	Limited Partnership Agreement	DEFM14A	000-51309	Annex F	2/4/2011
10.1	Drilling and operating agreement between the Partnership and PDC, as Managing General Partner	10-K	000-51309	10.1	02/26/2009
3.2	Certificate of limited partnership which reflects the organization of the Partnership under West Virginia law	10-K	000-51309	3.2	2/26/2009
10.3	Audited Consolidated Financial Statements for the year ended December 31, 2009 of Petroleum Development Corporation and its subsidiaries, as Managing General Partner of the Partnership	10-K	000-07246		03/04/2010
10.1	Drilling and operating agreement between the Partnership and PDC, as Managing General Partner	10-K	000-51309	10.1	2/26/2009
23.1	Consent of Ryder Scott Company, L.P., Petroleum Consultants					X
10.2	Form of assignment of leases to the Partnership	10-K	000-51309	10.2	2/26/2009
31.1	Rule 13a-14(a)/15d-14(c) Certification of Chief Executive Officer of Petroleum Development Corporation, the Managing General Partner of the Partnership.					X
10.3	Audited Consolidated Financial Statements for the year ended December 31, 2010 of Petroleum Development Corporation (dba PDC Energy) and its subsidiaries, as Managing General Partner of the Partnership	10-K	000-07246		2/24/2011
31.2	Rule 13a-14(a)/15d-14(c) Certification of Chief Financial Officer of Petroleum Development Corporation, the Managing General Partner of the Partnership.					X
10.4	Gas Purchase and Processing Agreement between Duke Energy Field Services, Inc.; United States Exploration, Inc.; and Petroleum Development Corporation, dated October 28, 1999 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10-12G/A Amend 3	000-53201	10.3	3/31/2009
32.1	Title 18 U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002) Certifications by Chief Executive Officer and Chief Financial Officer of Petroleum Development Corporation, the Managing General Partner of the Partnership.					X
10.5	Gas Purchase and Processing Agreement between Natural Gas Associates, a Colorado partnership, and Aceite Energy Corporation, Walker Exploratory Program 1982-A Limited and Cattle Creek Company, dated October 14, 1983 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10-12G/A Amend 3	000-53201	10.4	3/31/2009
99.2	Report of Independent Petroleum Consultants−Ryder Scott Company, LP					X
10.6	Gas Purchase and Processing Agreement between Natural Gas Associates, a Colorado partnership, and SHF Partnership, a Colorado general partnership, Trailblazer Oil and Gas, Inc., Alfa Resources, Inc., Pulsar Oil and Gas, Inc., Overthrust Oil Royalty Corporation, Corvette Petroleum Ltd., Robert Lanari, an individual, and Toby A Martinez, an individual, dated September 21, 1983 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)	10-12G/A Amend 3	000-53201	10.5	3/31/2009

- 37 50-

~~Index~~Table Of Contents

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing

Date

Filed

Herewith

10.7

Domestic Crude Oil Purchase Agreement with ConocoPhillips Company, dated January 1, 1993, as amended by agreements with Teppco Crude Oil, LLC dated August 2, 2007; September 24, 2007; October 17, 2007; January 7, 2008; January 15, 2008; and April 17, 2008 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)

10-12G/A Amend 3

000-53201

10.6

3/31/2009

10.8

Gas Purchase Agreement between Williams Production RMT Company, Riley Natural Gas Company and Petroleum Development Corporation, dated as of June 1, 2006 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)

10-12G/A Amend 3

000-53201

10.7

03/31/2009

10.9

Domestic Crude Oil Purchase Agreement between Suncor Energy Marketing Inc. and Petroleum Development Corporation, dated April 22, 2008 (filed by PDC as Managing General Partner for Rockies Region 2007 Limited Partnership)

10-Q

000-53201

10.1

5/18/2009

31.1

Rule 13a-14(a)/15d-14(c) Certification of Chief Executive Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership.

-51-

Table Of Contents

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing

Date

Filed

Herewith

31.2

Rule 13a-14(a)/15d-14(c) Certification of Chief Financial Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership.

32.1

Title 18 U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002) Certifications by Chief Executive Officer and Chief Financial Officer of Petroleum Development Corporation (dba PDC Energy), the Managing General Partner of the Partnership.

99.2

Report of Independent Petroleum Consultants−Ryder Scott Company, LP

-52-

Table Of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

PDC 2005-A Limited Partnership

By its Managing General Partner

Petroleum Development Corporation (dba PDC Energy)

By /s/ Richard W. McCullough

Richard W. McCullough

Chairman and Chief Executive Officer

~~March~~of ~~31,~~Petroleum ~~2010~~Development Corporation (dba PDC Energy)

March 30, 2011

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:

Signature	Title	~~Date~~	Date
/s/ Richard W. McCullough	Chairman and Chief Executive Officer	~~March 31, 2010~~	March 30, 2011
Richard W. McCullough	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal executive officer)
/s/ Gysle R. Shellum	Chief Financial Officer	~~March 31, 2010~~	March 30, 2011
Gysle R. Shellum	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal financial officer)
/s/ R. Scott Meyers	Chief Accounting Officer	~~March 31, 2010~~	March 30, 2011
R. Scott Meyers	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
	(Principal accounting officer)
/s/ Kimberly Luff Wakim	Director	March 31, 2010
/s/ Joseph E. Casabona	Director		March 30, 2011
Kimberly Luff Wakim	Petroleum Development Corporation
Joseph E. Casabona	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
/s/ Anthony J. Crisafio	Director	~~March 31, 2010~~	March 30, 2011
Anthony J. Crisafio	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
/s/ Jeffrey C. Swoveland	Director	~~March 31, 2010~~	March 30, 2011
Jeffrey C. Swoveland	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant
/s/ Joseph E. Casabona	Director	March 31, 2010
/s/ Kimberly Luff Wakim	Director		March 30, 2011
Joseph E. Casabona	Petroleum Development Corporation
Kimberly Luff Wakim	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant

- 38 53-

~~Index~~Table Of Contents

PDC 2005-A LIMITED PARTNERSHIP

Index to Financial Statements

Report of Independent Registered Public Accounting Firm	F-2
Balance Sheets - December 31, 2009 and 2008	F-3
Balance Sheets - December 31, 2010 and 2009	F-3
Statements of Operations - For the Years Ended December 31, 2009 and 2008	F-4
Statements of Operations - For the Years Ended December 31, 2010 and 2009	F-4
Statements of Partners' Equity - For the Years Ended December 31, 2009 and 2008	F-5
Statements of Partners' Equity - For the Years Ended December 31, 2010 and 2009	F-5
Statements of Cash Flows - For the Years Ended December 31, 2009 and 2008	F-6
Statements of Cash Flows - For the Years Ended December 31, 2010 and 2009	F-6
Notes to Financial Statements	F-7
Supplemental Oil and Gas Information - Unaudited	F-25
Supplemental Natural Gas, NGL and Crude Oil Information - Unaudited	F-23

F-1

~~Index~~Table Of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of the PDC 2005-A 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 2005-A Limited Partnership (the "Partnership") at December 31, ~~2009~~2010 and ~~2008~~2009, and the results of its operations and its cash flows for each of the two years in the period ended December 31, ~~2009~~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 39 to the financial statements, the Partnership has significant related party transactions with Petroleum Development Corporation and its subsidiaries.

/s/ PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

March 3130, ~~2010~~2011

F-2

~~Index~~Table Of Contents

PDC 2005-A LIMITED PARTNERSHIP

Balance Sheets

As of December 31, ~~2009~~2010 and ~~2008~~2009

Assets	~~2009~~2010			~~2008~~2009
Current assets:
Cash and cash equivalents	$	~~224~~381,~~751~~441		$	~~314~~224,~~610~~751
Accounts receivable		~~408~~322,~~544~~451			~~318~~408,~~421~~544
Oil inventory		33,305			30,950
Crude oil inventory		33,015			33,305
Due from Managing General Partner-derivatives		~~554~~871,~~898~~967			2554,~~100,443~~898
Due from Managing General Partner-other, net		~~355~~66,~~801~~582			1355,~~590,959~~801
Total current assets		1,~~577~~675,~~299~~456			41,~~355~~577,~~383~~299
Oil and gas properties, successful efforts method		44,419,132			44,267,285
Natural gas and crude oil properties, successful efforts method, at cost		44,472,739			44,419,132
Drilling advances to Managing General Partner		-			108,531
Less: Accumulated depreciation, depletion and amortization		(23,463,131	)		(20,809,309	)
Oil and gas properties, at cost		44,419,132			44,375,816
Natural gas and crude oil properties, net		21,009,608			23,609,823
Less: Accumulated depreciation, depletion and amortization		(20,809,309	)		(17,313,642	)
Due from Managing General Partner-derivatives		1,383,784			516,653
Oil and gas properties, net		23,609,823			27,062,174
Other assets		50,920			24,607
Due from Managing General Partner-derivatives		516,653			716,092
Total noncurrent assets		22,444,312			24,151,083
Other assets		24,607			-
Total Assets	$	24,119,768		$	25,728,382
Total noncurrent assets		24,151,083			27,778,266
Total Assets	$	25,728,382		$	32,133,649
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	4139,~~448~~844		$	6641,~~607~~448
Due to Managing General Partner-derivatives		~~529~~673,~~551~~976			-529,551
Total current liabilities		~~570~~713,~~999~~820			66570,~~607~~999
Due to Managing General Partner-derivatives		1,~~487~~051,~~222~~332			~~165~~1,~~957~~487,222
Asset retirement obligations		~~512~~540,~~800~~342			~~381~~512,~~260~~800
Total liabilities		2,~~571~~305,~~021~~494			~~613~~2,~~824~~571,021
Commitments and contingent liabilities
Partners' equity:
Managing General Partner		4,~~646~~377,~~456~~839			64,~~318~~646,~~947~~456
Limited Partners - 1,996.87 units issued and outstanding		1817,~~510~~436,~~905~~435			2518,~~200~~510,~~878~~905
Total Partners' equity		2321,~~157~~814,~~361~~274			3123,~~519~~157,~~825~~361
Total Liabilities and Partners' Equity	$	2524,~~728~~119,~~382~~768		$	3225,~~133~~728,~~649~~382

See accompanying notes to financial statements.

F-3

~~Index~~Table Of Contents

PDC 2005-A LIMITED PARTNERSHIP

Statements of Operations

For the Years Ended December 31, ~~2009~~2010 and ~~2008~~2009

	2009			2008
	2010			2009
Revenues:
Natural gas and oil sales	$	3,268,138		$	7,410,537
Natural gas, NGLs and crude oil sales	$	4,053,465		$	3,268,138
Commodity price risk management (loss) gain, net		(1,087,368	)		3,038,361
Commodity price risk management gain (loss), net		2,230,057			(1,087,368	)
Total revenues		26,~~180~~283,~~770~~522			102,~~448~~180,~~898~~770
Operating costs and expenses:
Natural gas and oil production costs		1,483,632			1,894,682
Natural gas, NGLs and crude oil production cost		1,399,976			1,483,632
Direct costs - general and administrative		~~442~~189,~~140~~149			~~344~~442,~~410~~140
Depreciation, depletion and amortization		32,~~495~~653,~~667~~822			23,~~857~~495,~~897~~667
Accretion of asset retirement obligations		827,~~969~~542			178,~~492~~969
Total operating costs and expenses		54,~~430~~270,~~408~~489			5,~~114~~430,~~481~~408
(Loss) income from operations		(3,249,638	)		5,334,417
Income (loss) from operations		2,013,033			(3,249,638	)
Interest expense		~~(2,338~~-	)		-(2,338	)
Interest income		~~33,815~~-			6433,~~420~~815
Net (loss) income	$	(3,218,161	)	$	5,398,837
Net income (loss)	$	2,013,033		$	(3,218,161	)
Net (loss) income allocated to partners	$	(3,218,161	)	$	5,398,837
Net income (loss) allocated to partners	$	2,013,033		$	(3,218,161	)
Less: Managing General Partner interest in net (loss) income		(643,632	)		1,079,767
Less: Managing General Partner interest in net income (loss)		402,607			(643,632	)
Net (loss) income allocated to Investor Partners	$	(2,574,529	)	$	4,319,070
Net income (loss) allocated to Investor Partners	$	1,610,426		$	(2,574,529	)
Net (loss) income per Investor Partner unit	$	(1,289	)	$	2,163
Net income (loss) per Investor Partner unit	$	806		$	(1,289	)
Investor Partner units outstanding		1,996.87			1,996.87

See accompanying notes to financial statements.

F-4

~~Index~~Table Of Contents

PDC 2005-A LIMITED PARTNERSHIP

Statements of Partners' Equity

For the Years Ended December 31, ~~2009~~2010 and ~~2008~~2009

	Investor Partners			Managing General Partner			Total
Balance, December 31, 2007	$	25,653,148		$	6,432,014		$	32,085,162
Balance, December 31, 2008	$	25,200,878		$	6,318,947		$	31,519,825
Distributions to partners		(4,771,340	)		(1,192,834	)		(5,964,174	)
Net income		4,319,070			1,079,767			5,398,837
Balance, December 31, 2008		25,200,878			6,318,947			31,519,825
Distributions to partners		(4,115,444	)		(1,028,859	)		(5,144,303	)
Net loss		(2,574,529	)		(643,632	)		(3,218,161	)
Balance, December 31, 2009	$	18,510,905		$	4,646,456		$	23,157,361
Distributions to partners		(2,684,896	)		(671,224	)		(3,356,120	)
Net income		1,610,426			402,607			2,013,033
Balance, December 31, 2010	$	17,436,435		$	4,377,839		$	21,814,274

See accompanying notes to financial statements.

F-5

~~Index~~Table Of Contents

PDC 2005-A LIMITED PARTNERSHIP

Statements of Cash Flows

For the Years Ended December 31, ~~2009~~2010 and ~~2008~~2009

	2009			2008
	2010			2009
Cash flows from operating activities:
Net (loss) income	$	(3,218,161	)	$	5,398,837
Net income (loss)	$	2,013,033		$	(3,218,161	)
Adjustments to net (loss) income to reconcile to net cash provided by operating activities:
Adjustments to net income (loss) to reconcile to net cash provided by operating activities:
Depreciation, depletion and amortization		32,~~495~~653,~~667~~822			23,~~857~~495,~~897~~667
Accretion of asset retirement obligations		827,~~969~~542			178,~~492~~969
Unrealized loss (gain) on derivative transactions		3,595,800			(2,806,271	)
Unrealized (gain) loss on derivative transactions		(1,475,665	)		3,595,800
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(90,123	)		422,289
Decrease (increase) in accounts receivable		86,093			(90,123	)
Increase in oil inventory		(2,355	)		(30,950	)
Decrease (increase) in crude oil inventory		290			(2,355	)
Increase in other assets		(2426,~~607~~313	)		-(24,607	)
Decrease in accounts payable and accrued expenses		(251,~~159~~604	)		(425,~~701~~159	)
Decrease in due from Managing General Partner, Net		1289,~~235,158~~219			~~161~~1,~~796~~235,158
Net cash provided by operating activities		43,~~975~~566,~~189~~417			64,~~016~~975,~~389~~189
Cash flows from investing activities:
Capital expenditures for oil and gas properties		(29,276	)		(31,260	)
Capital expenditures for natural gas and crude oil properties		(53,607	)		(29,276	)
Proceeds from drilling advance refund from Managing General Partner		~~108,531~~-			-108,531
Proceeds from Colorado tax refund on oil and gas properties		-			128,874
Net cash (used in) provided by investing activities		(53,607	)		79,255
Net cash provided by investing activities		79,255			97,614
Cash flows from financing activities:
Distributions to Partners		(53,~~144~~356,~~303~~120	)		(5,~~964~~144,~~174~~303	)
Net cash used in financing activities		(53,~~144~~356,~~303~~120	)		(5,~~964~~144,~~174~~303	)
Net (decrease) increase in cash and cash equivalents		(89,859	)		149,829
Net increase (decrease) in cash and cash equivalents		156,690			(89,859	)
Cash and cash equivalents, beginning of year		~~314~~224,~~610~~751			~~164~~314,~~781~~610
Cash and cash equivalents, end of year	$	~~224~~381,~~751~~441		$	~~314~~224,~~610~~751
Supplemental cash flow information:
Cash payments for:
Interest	$	~~2,338~~-		$	-2,338
Supplemental disclosure of non-cash activity:
Asset retirement obligation, with corresponding increase to oil and gas properties	$	122,571		$	-
Asset retirement obligation, with corresponding increase to natural gas and crude oil properties	$	-		$	122,571

See accompanying notes to financial statements.

F-6

~~Index~~Table Of Contents

PDC 2005-A LIMITED PARTNERSHIP

Notes to Financial Statements

~~Note~~NOTE 1 –- ~~General~~GENERAL

PDC 2005-A 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 ~~oil~~natural gas and ~~natural~~crude ~~gas~~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”), towhich ~~conduct~~conducts ~~and manage the Partnership’s~~ business~~. Upon~~ ~~completion~~under of the ~~drilling~~name ~~phase~~PDC ~~of the Partnership's wells~~Energy, ~~all~~to ~~additional~~conduct ~~general partners units were converted into units of limited partner interests~~ and ~~thereafter~~manage ~~became limited partners of~~ the Partnership’s business. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner ~~manages~~is authorized to manage all activities of the Partnership and ~~acts~~initiates asand ~~the~~completes ~~intermediary for~~ substantially all Partnership transactions.

As of December 31, ~~2009~~2010, there were 1,~~494~~502 Investor Partners. ~~Petroleum~~PDC ~~Development~~is ~~Corporation~~the ~~has been~~ designated ~~the~~ Managing General Partner of the Partnership and ~~has~~owns a 20% Managing General Partner ownership in the Partnership. ~~Throughout~~According to the ~~term~~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, ~~2009~~2010, the Managing General Partner has repurchased 2332.7521 units of Partnership interests from Investor Partners at an average price of $98,~~944~~752 per unit. As of December 31, 2010, the Managing General Partner owns 21.3% of the Partnership.

~~The~~On ~~following~~November ~~table~~16, ~~presents~~2010, the Partnership, ~~formation~~PDC and ~~organization~~its ~~information~~wholly-owned ~~through~~subsidiary, DP 2004 Merger Sub, LLC (“DP Merger Sub”), a Delaware limited liability company, entered into an agreement and plan of merger (the ~~completion~~“Merger Agreement”), in which PDC seeks to acquire the Partnership, subject to the vote and approval of a majority of the ~~drilling~~limited ~~phase~~partnership units held, as of the close of business on ~~March~~January 2031, ~~2006~~2011, by Investor Partners of the Partnership, other than PDC and its affiliates (“non-affiliated Investor Partners”). For more information on the proposed Merger Agreement, see Note 9, Transactions with Managing General Partner and Affiliates−Proposed Merger with PDC and DP 2004 Merger Sub, LLC, which follows. Pending the outcome of the proposed Merger Agreement, the Managing General Partner suspended, as of December 1, 2010, the opportunity for an individual non-affiliated Investor Partner to request that PDC repurchase their respective limited partnership units.

				Number of Partner Units
PDC 2005-A Limited Partnership Information	Date	Number of Partners		Additional General Partner Units			Limited Partner Units		Equity Percentage			Amount (millions)
West Virginia Limited Partnership Formation	November 30, 2004
Limited Partnership Termination Date	December 31, 2055
Public Sale of Securities and Funding	February 9, 2005
Investor Partners (1) Unit Cost: $20,000			1,523		1,872.08			124.79		80.00	%	$	39.9
PDC, Managing General Partner										20.00	%		8.8
Total funding													48.7
Syndication costs paid to third-party brokers													(4.0	)
Management Fee Paid to PDC													(0.6	)
Net funding available for drilling activities										100.00	%	$	44.1
Conversion of additional General Partners to Limited Partners	March 20, 2006				(1,872.08	)		1,872.08
Limited Partnership Units after Conversion					-			1,996.87

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

~~Executive~~The ~~Drilling~~preparation ~~Program~~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.

~~Executive~~Basis ~~officers~~ of the Managing General Partner were eligible to invest in an executive drilling program as approved by the Board of Directors. These executive officers profited from their participation in the executive drilling program because they invested in wells at cost and did not pay drilling compensation, management fees or broker commissions and therefore obtained an interest in the wells at a reduced price than that which was charged to the investing partners in a Partnership. Investor partners participating in drilling through a partnership were generally charged a profit or markup above the cost of the wells, management fees and commissions. See Note 3, Transactions with Managing General Partner and Affiliates.Presentation

~~Through the executive drilling program, certain former executive officers of PDC have invested in the wells developed by PDC in which the Partnership invested.~~ The ~~executive~~financial ~~program~~statements ~~allowed~~include ~~PDC~~only tothose sell working interests to PDC executive officers in the wells that PDC developed for the Partnership. Participating officers thereby owned parallel undivided working interests in all of the wells that the Partnership has invested in. Prior to the funding of the Partnershipassets, ~~each~~liabilities ~~executive~~and ~~officer~~results ~~who chose to participate in the executive program advised PDC~~ of ~~the~~operations ~~dollar amount~~ of ~~his investment participation, and thereby acquired a working interest in~~ the ~~wells~~partners in which ~~the~~relate ~~Partnership acquired a working interest, the acquired working interest being parallel~~ to the ~~working~~business ~~interest~~ of the Partnership ~~and the investor partners~~. The officers’ percentage in certain wells is proportionate to the Partnership’s working interest among all of the Partnership’s wells based upon the officers’ investment amount. PDC also had the option to sell working interests in these wells, also prior to the funding of the Partnership, to other parties unaffiliated with PDC. The aggregate ownership percentage of these former executive officers ranges from 0.17% to 0.19% in all of the wells drilled by the Partnership. The Board believed that having the executive officers invest in wells with PDC and other investor partners helped to create a commonality of interests much like share ownership creates a commonality of interests between the shareholders and executive officers. As of December 31, 2009, no current executive officer owns any beneficial interest in 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.

F-7

~~Index~~Table Of Contents

PDC 2005-A LIMITED PARTNERSHIP

Notes to Financial Statements

~~Note~~Accounts 2Receivable -and ~~Summary~~Allowance for Doubtful Accounts. The Partnership’s accounts receivable are from purchasers of ~~Significant~~natural ~~Accounting~~gas, ~~Policies~~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.

~~Basis~~Commitments. As Managing General Partner, PDC maintains performance bonds in the form of ~~Presentation~~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.

~~The~~Inventory. Inventory ~~financial~~consists ~~statements~~of ~~include~~crude ~~only those assets~~oil, ~~liabilities~~stated ~~and~~at ~~results~~the oflower ~~operations~~ of ~~the~~cost ~~partners which relate~~ to ~~the~~produce ~~business of the Partnership. The statements do not include any assets, liabilities, revenues~~ or ~~expenses attributable to any of the partners' other activities~~market.

~~Cash~~Derivative Financial Instruments. The Partnership is exposed to the effect of market fluctuations in the prices of natural gas and ~~Cash~~crude ~~Equivalents~~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.

~~The~~All ~~Partnership~~derivative ~~considers~~assets ~~all~~and ~~highly~~liabilities ~~liquid~~are ~~investments~~recorded ~~with~~on ~~original~~the ~~maturities~~balance ofsheets ~~three~~at ~~months~~fair orvalue. PDC, ~~less~~as toManaging beGeneral ~~cash~~Partner, ~~equivalents. The~~has ~~Partnership~~elected ~~maintains~~not ~~substantially~~to ~~all~~designate any of ~~its~~the ~~cash~~Partnership’s ~~and~~derivative ~~cash~~instruments ~~equivalents~~as hedges. Accordingly, changes in athe ~~bank~~fair ~~account~~value atof ~~one~~the ~~financial~~Partnership’s ~~institution. Prior~~derivative toinstruments ~~October~~are 3,recorded ~~2008,~~in the ~~balance~~Partnership’s instatements of operations and the Partnership’s ~~account~~net ~~was~~income ~~insured~~is bysubject ~~Federal~~to ~~Deposit~~greater ~~Insurance~~volatility ~~Corporation,~~than orif ~~FDIC,~~the upPartnership’s toderivative ~~$100,000. As~~instruments aqualified ~~result~~for ofhedge accounting. Changes in the ~~Emergency~~fair ~~Economic~~value ~~Stability~~of ~~Act,~~derivative instruments related to the ~~FDIC~~Partnership’s ~~limit~~natural ~~was~~gas ~~raised~~and tocrude ~~$250,000~~oil ~~effective~~sales ~~October~~are 3,recorded ~~2008~~in ~~through~~the ~~December~~line 31captioned, ~~2009~~“Commodity ~~and~~price ~~subsequently~~risk ~~extended~~management ~~through~~gain ~~December 31~~(loss), ~~2013~~net.” ~~The~~As positions designated to the Partnership ~~has~~settle, ~~not~~the ~~experienced~~realized gains and losses inare ~~any~~netted ~~such~~for ~~accounts~~distribution. Net ~~and~~realized ~~limits~~gains ~~its~~are ~~exposure~~paid to ~~credit~~the ~~loss~~Partnership byand ~~placing~~net ~~its~~realized ~~cash~~losses ~~and~~are deducted from the Partnership’s cash ~~equivalents~~distributions ~~with~~generated ~~high-quality~~from ~~financial~~production. The ~~institutions~~Partnership bears its designated share of counterparty risk.

~~Accounts~~Validation ~~Receivable~~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 ~~Allowance~~Note 4, Derivative Financial Instruments, for ~~Doubtful~~a ~~Accounts~~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.

~~The~~Natural ~~Partnership’s~~Gas ~~accounts receivable are from purchasers of oil~~ and ~~natural~~Crude ~~gas~~Oil ~~production~~Properties. ~~The~~Significant ~~Partnership~~accounting ~~sells~~polices ~~substantially~~related ~~all of its oil and natural gas~~ to ~~customers who purchase oil and natural gas from other partnerships managed by~~ the Partnership’s ~~Managing~~properties ~~General Partner. Inherent to the Partnership’s industry is the concentration of oil~~ and ~~natural~~equipment ~~gas~~are ~~sales~~discussed ~~made to few customers~~below. 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, industry or other conditions.

AsThe Partnership accounts for its natural gas and crude oil properties (the “Properties”) under the successful efforts method of ~~December~~accounting. ~~31,~~Costs ~~2009~~of proved developed producing properties and ~~2008,~~developmental dry hole costs are capitalized and depreciated or depleted by the ~~Partnership~~unit-of-production ~~did~~method ~~not~~based ~~record~~on anestimated ~~allowance~~proved ~~for~~developed ~~doubtful~~producing ~~accounts~~reserves. ~~Historically,~~Property ~~neither~~acquisition ~~PDC~~costs ~~nor~~are ~~any~~depreciated ofor depleted on the ~~other~~unit-of-production ~~partnerships~~method ~~managed~~based on estimated proved reserves. The Partnership calculates quarterly depreciation, depletion and amortization ("DD&A") expense by using as the denominator the Partnership’s ~~Managing~~estimated ~~General~~quarter-end ~~Partner~~reserves ~~have~~adjusted ~~experienced~~to ~~significant~~add ~~losses~~back oncurrent ~~accounts~~period ~~receivable~~production. ~~The~~Upon ~~Managing~~the ~~General~~sale ~~Partner~~or ~~periodically~~retirement ~~reviews~~of ~~accounts~~significant ~~receivable~~portions ~~for~~of ~~credit~~or ~~risks~~complete ~~resulting~~fields ~~from~~of ~~changes~~depreciable inor depletable property, the ~~financial~~net ~~condition~~book value thereof, less proceeds or salvage value, is recognized in the statement of ~~its~~operations ~~customers~~as a gain or loss. ~~The~~Upon ~~Partnership~~the ~~did~~sale ~~not~~of ~~incur~~individual ~~any~~wells, ~~losses~~the onproceeds ~~accounts~~are ~~receivable~~credited ~~for~~to ~~the~~accumulated ~~years~~DD&A. See ~~ended~~Supplemental ~~December~~Natural 31Gas, ~~2009~~NGL and ~~2008. For~~Crude ~~more~~Oil Information – Unaudited, Net Proved Reserves for additional information ~~concerning~~regarding the Partnership’s ~~concentration~~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 ~~credit~~natural ~~risk~~gas and crude oil wells. Accordingly, all such funds were advanced to the Managing General ~~Partner’s~~Partnership ~~evaluation~~as of ~~that~~the ~~risk,~~last ~~see~~day ~~Note~~of 7,the ~~Concentration~~year ofin ~~Credit~~which ~~Risk,~~the ~~below~~Partnership was formed. The Partnership does not maintain an inventory of undrilled leases.

Commitments and Contingencies

On behalf of and to the benefit of the Partnership and other partnerships for which PDC serves as Managing General Partner, the Managing General Partner maintains a margin deposit with counterparties on outstanding derivative contracts and also maintains bonds in the form of certificates of deposit for the plugging and abandoning of wells as required by various governmental agencies. Since these deposits represent general obligations of the Managing General Partner and are not specific and identifiable as obligations of the Partnership, no amounts are recorded by the Partnership related to these contingent deposits.

F-8

~~Index~~Table Of Contents

PDC 2005-A LIMITED PARTNERSHIP

Notes to Financial Statements

~~Inventories~~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 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.

~~Oil~~Proved ~~inventories~~Property ~~are~~Impairment. The ~~stated~~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 ~~lower~~Managing General Partner reasonably estimates the commodities to be sold. The estimates of ~~average~~future ~~lifting~~prices ~~cost~~may ordiffer 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 ~~removed~~determined using prices from the forward price curve at ~~carrying~~the ~~value~~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. The Partnership recognized no impairment of its natural gas and crude oil properties since inception to December 31, 2010.

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~~gas, NGLs and ~~Oil~~crude ~~Properties~~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.

~~The~~Income ~~Partnership accounts for its oil and natural gas properties (the “Properties”) under the successful efforts method of accounting~~Taxes. Since ~~Costs of proved developed producing properties and developmental dry hole costs are depreciated or depleted by~~ the ~~unit-of-production~~taxable ~~method~~income ~~based on estimated proved developed producing natural gas and oil reserves. Property acquisition costs are depreciated~~ or ~~depleted~~loss ~~on the unit-~~of~~-production~~ ~~method based on estimated proved natural gas and oil reserves. See Supplemental Oil and Gas Information – Unaudited, Net Proved Natural Gas and Oil Reserves for additional information regarding~~ the Partnership’s ~~reserve~~is ~~reporting. In~~reported ~~accordance~~in ~~with~~ the ~~Agreement,~~separate ~~all~~tax ~~capital~~returns ~~contributed~~of to the ~~Partnership~~individual ~~after~~investor ~~deducting~~partners, ~~syndication~~no ~~costs~~provision ~~and~~has abeen ~~one-time~~made ~~management fee was used solely~~ for ~~the~~income ~~drilling~~taxes ofby ~~oil and natural gas 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.~~

~~Partnership~~Asset ~~estimates~~Retirement ofObligations. The ~~proved~~Partnership ~~reserves~~accounts ~~are~~for ~~based~~asset onretirement ~~those~~obligations ~~quantities~~by ofrecording ~~natural~~the ~~gas~~fair ~~and~~value ~~oil~~of ~~which,~~Partnership bywell ~~analysis~~plugging ofand ~~geoscience~~abandonment ~~and~~obligations ~~engineering~~when ~~data~~incurred, ~~are~~which ~~estimated~~is ~~with~~at ~~reasonable~~the ~~certainty~~time ~~to be economically producible in~~ the ~~future~~well ~~from~~is ~~known~~spudded. Upon ~~reservoirs~~initial ~~under~~recognition ~~existing~~of ~~conditions,~~an ~~operating~~asset ~~methods~~retirement ~~and government regulations. Annually~~obligation, the ~~Managing~~Partnership ~~General~~increases ~~Partner~~the ~~engages~~carrying ~~independent~~amount ~~petroleum engineers to prepare a reserve and economic evaluation~~ of the ~~Partnership’s~~long-lived ~~properties~~asset onby athe ~~well-by-well~~same ~~basis~~amount as ofthe ~~December 31~~liability. ~~Additionally~~Over time, the ~~Partnership~~liabilities ~~adjusts~~are ~~natural~~accreted ~~gas and oil reserves~~ for ~~major well rework or abandonment during~~ the ~~year~~change asin ~~needed.~~present value. The ~~process~~initial ofcapitalized ~~estimating~~costs ~~and~~are ~~evaluating~~depleted ~~natural~~over ~~gas~~the ~~and~~useful ~~oil~~lives ~~reserves~~of ~~is complex, requiring significant decisions in~~ the ~~evaluation~~related ~~of available geological~~assets, ~~geophysical,~~through ~~engineering~~charges ~~and~~to ~~economic~~DD&A ~~data~~expense. If ~~The~~the ~~data~~fair ~~for~~value ~~a given property may also change substantially over time as a result~~ of ~~numerous~~the ~~factors,~~estimated ~~including~~asset ~~additional~~retirement ~~development~~obligation ~~activity~~changes, ~~evolving~~an ~~production~~adjustment ~~history~~is ~~and~~recorded ato ~~continual~~both ~~reassessment of~~ the ~~viability~~asset ofretirement ~~production~~obligation ~~under~~and ~~changing~~the ~~economic~~asset ~~conditions~~retirement cost. Revisions ~~As a result, revisions~~ in ~~existing~~estimated ~~reserve~~liabilities ~~estimates~~can ~~occur~~result from ~~time~~revisions toof ~~time.~~estimated ~~Although~~inflation ~~every reasonable effort is made to ensure that reported reserve estimates represent our most accurate assessments possible~~rates, ~~the~~escalating ~~subjective~~retirement ~~decisions~~costs and ~~variances~~changes in ~~available data for various properties increase~~ the ~~likelihood~~estimated timing of ~~significant~~settling ~~changes~~retirement ~~in these estimates over time~~obligations. See ~~Because~~Note ~~estimates~~6, ofAsset ~~reserves~~Retirement ~~significantly~~Obligations ~~affect~~for ~~our~~a ~~depreciation,~~reconciliation ~~depletion~~of ~~and~~the ~~amortization~~changes ~~(“DD&A”) expense, a change~~ in the Partnership’s ~~estimated~~asset ~~reserves~~retirement ~~could~~obligation ~~have~~from anJanuary ~~effect~~1, on2009, ~~the~~to ~~Partnership’s~~December ~~net~~31, ~~income~~2010.

The Partnership accounts for the impairment of long-lived assets by periodically assessing its proved natural gas and 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 Partnership reasonably estimates the commodities to be sold. The estimates of future prices may differ from current market prices of oil and natural gas. Downward revisions in estimates of 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 oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, impairment is based on estimated fair value utilizing a future discounted cash flow analysis and is measured by the amount by which the net capitalized costs exceed their fair value. Due to the availability of new reserve information, the Partnership reviewed its proved oil and natural gas properties for impairment at December 31, 2009. The Partnership did not incur impairment loss as a result of this review.

Revenue Recognition

Natural Gas Sales. Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas 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 contracts 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, so that the price of the natural gas fluctuates to remain competitive with other available gas supplies.

F-9

~~Index~~Table Of Contents

PDC 2005-A LIMITED PARTNERSHIP

Notes to Financial Statements

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~~net-~~Back~~back” method of accounting for transportation arrangements of the Partnership’s natural gas sales. The Managing General Partner ~~markets~~sells the Partnership’s natural gas at the wellhead, ~~collects a price,~~ 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.

~~Oil~~Recent ~~Sales. Sales~~Accounting of oil are recognized when persuasive evidence of a sales arrangement exists, the oil is verified as produced and is delivered from storage tanks at well locations to a purchaser, collection of revenue from the sale is reasonably assured and the sales price is determinableStandards. The Partnership is currently able to sell all the oil that it can produce under existing sales contracts with petroleum refiners and marketers. The Partnership does not refine any of its oil production.

The ~~Partnership’s~~following ~~crude~~standards ~~oil~~have ~~production~~been isrecently ~~sold to purchasers 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.~~adopted:

~~The~~Fair ~~Partnership~~Value ~~presents~~Measurements ~~any~~and ~~taxes~~Disclosures. In ~~collected~~January ~~from~~2010, ~~customers~~the ~~and~~Financial ~~remitted~~Accounting Standards Board (“FASB”) issued changes clarifying existing disclosure requirements related to afair ~~government~~value ~~agency~~measurements. The onupdate also added a ~~net~~new ~~basis~~requirement to disclose fair value transfers in ~~its~~and ~~statements~~out of ~~operations~~Levels in1 ~~accordance~~and ~~with~~2 ~~accounting~~and ~~standards~~describe the reasons for ~~revenue~~the ~~recognition~~transfers. The ~~regarding~~adoption ~~taxes~~of ~~collected~~these ~~from~~changes ~~customers~~as ~~and~~of ~~remitted~~January to1, ~~governments~~2010, did not have a material impact on the Partnership’s accompanying financial statements.

~~Asset~~The ~~Retirement~~following ~~Obligations~~standards have been recently issued:

~~The~~Fair ~~Partnership~~Value ~~accounts~~Measurements ~~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~~Disclosures. ~~Upon~~In ~~initial~~January ~~recognition of an asset retirement obligation~~2010, the ~~Partnership~~FASB ~~increases~~issued ~~the~~changes ~~carrying~~clarifying ~~amount~~existing ofdisclosure ~~the~~requirements ~~long-lived~~and ~~asset~~requiring bygross ~~the~~presentation ~~same~~of ~~amount~~activities aswithin the ~~liability. The~~Level ~~asset~~3 ~~retirement~~roll ~~obligations are accreted~~forward, ~~over~~whereby ~~the~~entities ~~estimated~~must ~~life~~present ofseparately ~~the~~information ~~related~~about ~~asset~~purchases, ~~for~~sales, ~~the~~issuances ~~change~~and ~~in present value~~settlements. The ~~initial~~update ~~capitalized~~also ~~costs~~added ~~are~~a ~~depleted~~new ~~over~~requirement ~~the~~to ~~useful~~disclose ~~lives~~fair ofvalue ~~the~~transfers ~~related~~in ~~assets,~~and ~~through~~out ~~charges~~of toLevels ~~DD&A~~1 ~~expense. If~~and ~~the~~2 ~~fair~~and ~~value~~describe of the ~~estimated~~reasons ~~asset~~for ~~retirement~~the ~~obligation~~transfers. These changes, anwill ~~adjustment~~be iseffective ~~recorded~~for ~~to both~~ the ~~asset~~Partnership’s ~~retirement~~financial ~~obligation~~statements ~~and~~issued for the ~~asset~~first ~~retirement~~interim ~~cost. Revisions~~or inannual ~~estimated~~reporting ~~liabilities~~period ~~can~~beginning ~~result~~after ~~from~~December ~~revisions~~15, ~~of estimated inflation rates~~2009, ~~escalating~~except ~~costs~~ for ~~future~~gross ~~dismantlement,~~presentation ~~restoration,~~of ~~reclamation~~the ~~and~~Level ~~abandonment~~3 ~~and~~roll ~~changes~~forward, inwhich ~~the~~will ~~estimate~~become ofeffective ~~retirement~~for ~~obligation~~annual ~~settlement~~reporting atperiods ~~the~~beginning ~~end~~after ofDecember ~~each~~15, ~~well~~2010. The Partnership’s ~~productive~~adoption ~~service~~did ~~life. See~~not ~~Note~~have 8,a ~~Asset~~material ~~Retirement~~effect ~~Obligations~~on ~~for~~the aPartnership’s ~~reconciliation~~financial ofstatements ~~asset~~and ~~retirement~~related ~~obligation activity~~disclosures.

~~Derivative~~Internal Control over Financial ~~Instruments~~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 ~~Partnership~~Managing isGeneral ~~exposed~~Partner tohas ~~the~~evaluated ~~effect of market fluctuations in~~ the ~~prices~~Partnership’s ofactivities ~~natural~~subsequent ~~gas~~to ~~and~~December ~~oil. Price~~31, ~~risk~~2010 ~~represents~~through the ~~potential~~issuance ~~risk~~ of ~~loss from adverse changes in~~ the ~~market~~financial ~~price~~statements, ofand ~~natural~~has ~~gas~~concluded ~~and~~that ~~oil~~no ~~commodities. The~~material ~~Managing~~subsequent ~~General~~events ~~Partner~~have ~~employs~~occurred ~~established~~that ~~policies~~would ~~and~~require ~~procedures~~additional torecognition ~~manage~~in the ~~risks~~Partnership’s ~~associated~~financial ~~with~~statements ~~these~~or ~~market~~disclosure ~~fluctuations~~in ~~using~~the ~~commodity~~notes ~~derivative~~to ~~instruments. The~~the ~~Managing General Partner~~Partnership’s ~~policy~~financial ~~prohibits the use of natural gas and oil derivative instruments for speculative purposes~~statements.

All derivative assets and liabilities are recorded on the balance sheets at fair value. Recognition and classification of realized and unrealized gains and losses resulting from maturities and changes in fair value of open derivatives depends on the purpose for issuing or holding the derivative. Since PDC, as Managing General Partner, does not designate the Partnership’s derivative instruments as hedges, the Partnership does not currently qualify for the use of hedge accounting. Therefore, 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 oil sales are recorded in the line captioned, “Commodity price risk management, net.”

F-10

~~Index~~Table Of Contents

PDC 2005-A LIMITED PARTNERSHIP

Notes to Financial Statements

~~Validation~~NOTE of3 a- ~~contract’s~~FAIR ~~fair~~VALUE ~~value~~OF isFINANCIAL 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 4, Fair Value Measurements and Note 5, 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, 2009 and 2008.INSTRUMENTS

~~Income~~Derivative ~~Taxes~~Financial Instruments

~~Since~~Determination of Fair Value. The Partnership’s fair value measurements are estimated pursuant to a fair value hierarchy that requires the ~~taxable~~Partnership ~~income~~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 ~~loss~~liability as of the ~~Partnership~~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 ~~reported~~significant to a fair value measurement in its entirety determines the ~~separate~~applicable ~~tax~~level ~~returns~~in the fair value hierarchy. Assessing the significance of a particular input to the ~~individual~~fair ~~investor~~value ~~partners~~measurement in its entirety requires judgment, noconsidering ~~provision~~factors ~~has~~specific ~~been~~to ~~made~~the ~~for~~asset ~~income~~or ~~taxes~~liability, byand may affect the ~~Partnership~~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:

~~Production~~· ~~Tax~~Level ~~Liability~~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.

~~The~~· ~~Partnership~~Level is2 ~~responsible~~– ~~for~~Inputs ~~production~~other ~~taxes~~than ~~which~~quoted ~~are~~prices ~~primarily~~included ~~made~~within upLevel of1 ~~severance~~that ~~and~~are ~~property~~either ~~taxes~~directly toor beindirectly ~~paid~~observable tofor the ~~states~~asset ~~and~~or ~~counties~~liability, inincluding ~~which~~(i) ~~the~~quoted ~~Partnership~~prices ~~produces~~for ~~oil~~similar ~~and~~assets ~~natural~~or ~~gas.~~liabilities ~~The~~in ~~Partnership’s~~active ~~share~~markets, of(ii) ~~these~~quoted ~~taxes~~prices isfor ~~expensed~~identical toor ~~the~~similar ~~account~~assets ~~“Natural~~or ~~gas~~liabilities ~~and~~in ~~oil~~inactive ~~production~~markets, ~~costs.” The~~(iii) ~~Partnership’s~~inputs ~~production~~other ~~taxes~~than ~~payable~~quoted prices that are ~~included~~observable infor the ~~caption~~asset ~~“Accounts~~or ~~payable~~liability and ~~accrued~~(iv) ~~expenses”~~inputs onthat ~~the~~are ~~Partnership’s~~derived ~~balance~~from ~~sheets~~observable market data by correlation or other means.

~~Use~~· ofLevel ~~Estimates~~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 ~~has~~measures ~~made~~the afair ~~number~~value of ~~estimates~~its ~~and~~derivative ~~assumptions~~instruments ~~relating~~based upon quoted market prices, where available. The valuation determination includes: (1) identification of the inputs to the ~~reporting~~fair value methodology through the review of ~~assets~~counterparty statements and ~~liabilities~~other ~~and~~supporting ~~revenues~~documentation, ~~and~~(2) ~~expenses~~determination ~~and~~of the ~~disclosure~~validity of ~~contingent~~the ~~assets~~source ~~and~~of ~~liabilities~~the inputs, (3) corroboration of the original source of inputs through access to ~~prepare~~multiple ~~these~~quotes, ~~Partnership~~if ~~financial~~available, ~~statements~~or other information and (4) monitoring changes in ~~conformity~~valuation ~~with~~methods ~~accounting~~and ~~principles~~assumptions. The ~~generally~~methods ~~accepted~~described inabove ~~the~~may ~~United~~produce ~~States~~a fair value calculation that may not be indicative of ~~America~~future fair values. The ~~Actual~~Managing ~~results~~General’s ~~could~~valuation ~~differ~~determination ~~from~~also ~~those~~gives ~~estimates~~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 ~~Estimates~~Managing ~~which~~General Partner primarily uses financial institutions, who are ~~particularly~~also ~~significant~~major lenders in the Managing General Partner’s credit facility agreement, as counterparties to the ~~financial~~Managing ~~statements~~General ~~include~~Partner’s ~~estimates~~derivative contracts. The Managing General Partner has evaluated the credit risk of ~~natural~~the ~~gas~~counterparties holding the Partnership’s derivative assets using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and ~~oil~~the ~~reserves~~duration of each outstanding derivative position. Based on the Managing General Partner’s evaluation, ~~future~~the ~~cash~~Managing ~~flows~~General ~~from~~Partner ~~oil~~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 ~~natural~~while ~~gas~~the ~~properties~~Managing ~~which~~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 inby ~~assessing~~other ~~impairment~~market participants, the use of ~~long-lived~~different ~~assets~~methodologies, ~~estimated~~or ~~production~~assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value. For more information concerning the Partnership’s concentration of credit risk and ~~severance~~the ~~taxes,~~Managing ~~asset~~General ~~retirement~~Partner’s ~~obligations~~evaluation of that risk, ~~and~~see ~~valuation~~Note 5, Concentration of ~~derivative~~Risk, ~~instruments~~below.

Recently Adopted Accounting Standards

Accounting Standards Codification

In June 2009, the Financial Accounting Standards Board, or FASB, issued the FASB Accounting Standards Codification™ (the “Codification”), thereby establishing the Codification as the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in conformity with U.S. Generally Accepted Accounting Principles, or GAAP. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The FASB will no longer issue new standards in the form of Statements, FASB Staff Positions, or Emerging Issues Task Force Abstracts; instead, the FASB will issue Accounting Standards Updates. Accounting Standards Updates will not be authoritative in their own right as they will only serve to update the Codification. These changes and the Codification itself do not change GAAP. Effective July 1, 2009, the Partnership adopted the Codification. Other than the manner in which new accounting guidance is referenced, the adoption of the Codification did not have any impact on the Partnership’s financial statements.

Subsequent Events

In May 2009, the FASB issued changes regarding subsequent events, which establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. Specifically, the guidance sets forth the period after the balance sheet date during which the Managing General Partner should evaluate events or transactions that may occur for potential recognition or disclosure in the Partnership’s financial statements, the circumstances under which the Partnership should recognize events or transactions occurring after the balance sheet date in the Partnership’s financial statements, and the disclosures that the Partnership should make about events or transactions that occurred after the balance sheet date. The Partnership adopted the guidance as of June 30, 2009. See Subsequent Events, below.

F-11

~~Index~~Table Of Contents

PDC 2005-A LIMITED PARTNERSHIP

Notes to Financial Statements

~~Fair~~The ~~Value~~following ~~Measurements~~table presents, for each hierarchy level, the Partnership’s assets and ~~Disclosures~~liabilities, including both current and non-current portions, measured at fair value on a recurring basis as of December 31, 2010 and 2009.

In August 2009, the FASB issued changes regarding fair value measurements and disclosures to reduce potential ambiguity in financial reporting when measuring the fair value of liabilities. These changes clarify existing guidance that in circumstances in which a quoted price in an active market for the identical liability is not available, an entity is required to measure fair value using either a valuation technique that uses a quoted price of either a similar liability or a quoted price of an identical or similar liability when traded as an asset, or another valuation technique that is consistent with the principles of fair value measurements, such as an income approach (e.g., present value technique). This guidance also states that both a quoted price in an active market for the identical liability and a quoted price for the identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are Level 1 fair value measurements. These changes become effective for the Partnership on October 1, 2009. The adoption of these changes did not have a material impact on the Partnership’s financial statements.

	Level 1			Level 3			Total

As of December 31, 2009
Assets:
Commodity based derivatives	$	520,527		$	551,024		$	1,071,551
Total assets		520,527			551,024			1,071,551

Liabilities:
Commodity based derivatives		(41,267	)		(90,592	)		(131,859	)
Basis protection derivative contracts		-			(1,884,914	)		(1,884,914	)
Total liabilities		(41,267	)		(1,975,506	)		(2,016,773	)

Net asset (liability)	$	479,260		$	(1,424,482	)	$	(945,222	)

As of December 31, 2010
Assets:
Commodity based derivatives	$	2,151,540		$	104,211		$	2,255,751
Total assets		2,151,540			104,211			2,255,751

Liabilities:
Commodity based derivatives		-			(131,171	)		(131,171	)
Basis protection derivative contracts		-			(1,594,137	)		(1,594,137	)
Total liabilities		-			(1,725,308	)		(1,725,308	)

Net asset (liability)	$	2,151,540		$	(1,621,097	)	$	530,443

InThe ~~February~~following ~~2008,~~table ~~the~~presents FASB delayed by one year (to January 1, 2009) the fair value measurements and disclosure requirements for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a ~~recurring~~reconciliation ~~basis (at least annually). The January 1, 2009, adoption~~ of the ~~fair value measurements and disclosure requirements for the~~ Partnership’s ~~nonfinancial~~Level ~~assets~~3 ~~and~~fair ~~liabilities~~value ~~did not have a material impact on the Partnership’s financial statements~~measurements. ~~See Note 4, Fair Value Measurements.~~

Derivatives and Hedging Disclosures

	December 31,
	2010			2009
Fair value, net (liability) asset beginning of year	$	(1,424,482	)	$	2,650,578
Changes in fair value included in statement of operations line item:
Commodity price risk management gain (loss), net		47,018			(1,566,628	)
Settlements		(243,633	)		(2,508,432	)
Fair value, net liability end of year	$	(1,621,097	)	$	(1,424,482	)

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	$	(143,391	)	$	(1,894,127	)

InSee ~~March~~Note ~~2008~~4, ~~the~~Derivative ~~FASB~~Financial ~~issued changes regarding the disclosure requirements for derivative instruments and hedging activities. Pursuant to the changes~~Instruments, ~~enhanced disclosures are required to provide information about (a) how and why the Partnership uses derivative instruments, (b) how the Partnership accounts~~ for ~~derivative~~additional ~~instruments~~disclosure ~~and~~ related ~~hedged~~to ~~items and (c) how derivative instruments and related hedged items affect~~ the Partnership’s ~~financial~~derivative ~~position,~~ financial ~~performance and cash flows~~instruments. The Partnership adopted these changes effective January 1, 2009. The adoption did not have a material impact on the Partnership’s financial statements. See Note 5, Derivative Financial Instruments.

~~Oil~~Non-Derivative ~~and~~Financial ~~Gas~~Assets ~~Reserve Estimation~~ and ~~Reporting~~Liabilities.

InThe ~~January~~carrying ~~2009,~~values ~~the SEC published its final rule regarding the modernization~~ of ~~oil and gas reporting, which modifies~~ the ~~SEC’s~~financial ~~reporting~~instruments ~~and~~comprising ~~disclosure~~current ~~rules~~assets ~~for natural gas~~ and ~~oil~~current ~~reserves. The~~liabilities ~~most~~approximate ~~notable~~fair ~~changes of the final rule include the replacement of the single day period-end pricing to~~ value ~~natural~~due ~~gas and oil reserves~~ to athe 12short-~~month~~term ~~average~~maturities of ~~the~~these ~~first day of the month price for each month within the reporting period~~instruments. The final rule also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules. The revised reporting and disclosure requirements were effective for the Partnership as of December 31, 2009. Early adoption was not permitted.

InSee ~~January~~Note ~~2010,~~2 ~~the~~– ~~FASB~~Summary ~~issued~~of ~~changes~~Significant inAccounting ~~its~~Policies−Property ~~oil~~ and ~~gas~~Equipment, ~~reserve~~Natural ~~estimation~~Gas and ~~disclosure~~Crude ~~requirements~~Oil toProperties ~~align~~and ~~them~~−Asset ~~with~~Retirement ~~the~~Obligations ~~SEC's~~for ~~final~~a ~~rule~~discussion ~~discussed~~of ~~above. These~~how ~~changes were also effective for~~ the Partnership asdetermined offair ~~December~~value ~~31,~~for ~~2009~~these obligations.

The Partnership applied the above changes to the Partnership’s financial statements of and for the year ended December 31, 2009. As a result, the Partnership’s fourth quarter DD&A calculation was based on proved developed producing reserves that were calculated using the new SEC reserve reporting guidelines; whereas, DD&A calculations for the first three quarters of 2009 were based on the prior methodology. The impact of using the 12-month average pricing methodology specified under the new SEC reporting rules resulted in an increase of the Partnership’s fourth quarter DD&A expense of approximately $60,000.

F-12

~~Index~~Table Of Contents

PDC 2005-A LIMITED PARTNERSHIP

Notes to Financial Statements

~~Recently~~NOTE ~~Issued~~4 ~~Accounting~~- ~~Standards~~DERIVATIVE FINANCIAL INSTRUMENTS

~~Consolidation~~The –Partnership’s ~~Variable~~results ~~Interest~~of ~~Entities~~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 1,227,727 MMbtu of natural gas and 5,949 Bbls of crude oil. Partnership policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes.

InThe ~~June~~Managing ~~2009,~~General ~~the~~Partner ~~FASB~~uses ~~issued~~natural ~~changes~~gas ~~regarding~~and ancrude ~~entity’s~~oil ~~analysis~~commodity derivative instruments to ~~determine~~manage ~~whether~~price ~~any~~risk offor ~~its~~PDC ~~variable~~as ~~interests~~well ~~constitute~~as ~~controlling~~its ~~financial~~sponsored ~~interests~~drilling inpartnerships. The aManaging ~~variable~~General ~~interest~~Partner ~~entity. This~~sets ~~analysis~~these ~~identifies~~instruments for PDC and the ~~primary~~various ~~beneficiary~~partnerships ofmanaged aby ~~variable~~PDC ~~interest~~jointly ~~entity~~by asarea ~~the~~of ~~enterprise~~operations, ~~that~~whereby ~~has~~the ~~both~~allocation of derivative positions between PDC and each partnership is set at a fixed quantity. New positions have specific designations relative to the ~~following~~applicable ~~characteristics:~~partnership.

·As ~~the~~of ~~power~~December to31, ~~direct~~2010, the ~~activities~~Partnership’s ofderivative ainstruments ~~variable~~were ~~interest~~comprised ~~entity~~of ~~that~~commodity ~~most~~collars ~~significantly~~and ~~impact~~swaps ~~the~~and ~~entity’s~~basis ~~economic~~protection ~~performance and~~swaps.

· Collars contain a fixed floor price (put) and ceiling price (call). If the ~~obligation~~index toprice ~~absorb~~falls ~~losses~~below ofthe fixed put strike price, PDC, as Managing General Partner receives the ~~entity~~market ~~that~~price ~~could~~from ~~potentially~~the bepurchaser ~~significant~~and toreceives the ~~variable~~difference ~~interest~~between ~~entity~~the orput strike price and index price from the ~~right~~counterparty. toIf ~~receive~~the ~~benefits~~index price exceeds the fixed call strike price, PDC, as Managing General Partner, receives the market price from the ~~entity~~purchaser ~~that~~and ~~could~~pays ~~potentially~~the bedifference ~~significant~~between the call strike price and index price to the ~~variable~~counterparty. ~~interest~~If ~~entity~~the index price is between the put and call strike price, no payments are due to or from the counterparty.

~~Additionally,~~· ~~the~~Swaps ~~entity~~are isarrangements ~~required~~that toguarantee ~~assess~~a ~~whether~~fixed itprice. ~~has~~If anthe ~~implicit~~index ~~financial~~price ~~responsibility~~is tobelow ~~ensure~~the ~~that~~fixed acontract ~~variable~~price, ~~interest~~PDC, ~~entity~~as ~~operates~~Managing asGeneral ~~designed~~Partner, ~~when~~receives ~~determining~~the ~~whether~~market itprice ~~has~~from the ~~power~~purchaser toand ~~direct~~receives the ~~activities~~difference ofbetween the ~~variable~~index ~~interest~~price ~~entity~~and ~~that~~the ~~most~~fixed ~~significantly~~contract ~~impact~~price from the ~~entity’s~~counterparty. ~~economic~~If ~~performance. The~~the ~~guidance~~index ~~also~~price ~~requires~~is ~~ongoing~~above ~~reassessments~~the offixed ~~whether~~contract anprice, ~~enterprise~~PDC, isas ~~the~~Managing ~~primary~~General ~~beneficiary~~Partner, ofreceives athe ~~variable~~market ~~interest~~price ~~entity. These~~from ~~changes~~the ~~are~~purchaser ~~effective~~and ~~for~~pays the ~~Partnership’s~~difference ~~financial~~between ~~statements~~the ~~issued~~index ~~for~~price ~~fiscal~~and ~~years~~the ~~beginning~~fixed ~~after~~contract ~~November~~price ~~15,~~to ~~2009,~~the ~~with~~counterparty. ~~earlier~~If ~~adoption~~the ~~prohibited.~~index ~~These~~price ~~changes~~and ~~became~~contract ~~effective~~price ~~for~~are the ~~Partnership on January 1~~same, ~~2010~~no ~~and~~payment ~~are~~is ~~not~~due ~~expected~~ to ~~have~~or afrom ~~material impact on~~ the ~~Partnership’s financial statements when adopted in 2010~~counterparty.

~~Fair~~· ~~Value~~Basis ~~Measurements~~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 ~~Disclosures~~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.

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 is evaluating the impact that adoption will have on the Partnership’s financial statements and related disclosures.

Subsequent Events

The Managing General Partner has evaluated the Partnership’s activities subsequent to December 31, 2009 through the date of this report, and has concluded that no material subsequent events have occurred that would require recognition in the Partnership’s financial statements or disclosure in the notes to 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 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.

F-13

~~Index~~Table Of Contents

PDC 2005-A LIMITED PARTNERSHIP

Notes to Financial Statements

The following table presents ~~transactions with~~ the ~~Managing~~location ~~General~~and ~~Partner~~fair ~~reflected~~value inamounts of the ~~balance~~Partnership’s ~~sheet~~derivative ~~line~~instruments ~~item~~on ~~– Due from (to) Managing General Partner-other, net which remain undistributed or unsettled with~~ the ~~Partnership’s~~accompanying ~~investors~~balance sheets as of ~~the~~December ~~dates~~31, ~~indicated~~2010 and 2009.

		December 31,
Derivative instruments not	Balance Sheet		December 31,
		2009			2008
designated as hedge (1):	Line Item		2010			2009
Natural gas and oil sales revenues collected from the Partnership's third-party customers		$	392,255		$	565,638
Derivative Assets:
Commodity Price Risk Management, Realized Gains			396,498			738,074
Current
Other (1)			(432,952	)		287,247
Commodity contracts	Due from Managing General Partner- derivatives		$	871,967		$	554,898
Total Due from Managing General Partner - other, net		$	355,801		$	1,590,959
Non Current
Commodity contracts	Due from Managing General Partner- derivatives			1,383,784			516,653
Total Derivative Assets				2,255,751			1,071,551
Derivative Liabilities:
Current
Commodity contracts	Due to Managing General Partner- derivatives			131,171			42,274
Basis protection contracts	Due to Managing General Partner- derivatives			542,805			487,277
Non Current
Commodity contracts	Due to Managing General Partner- derivatives			-			89,584
Basis protection contracts	Due to Managing General Partner- derivatives			1,051,332			1,397,638
Total Derivative Liabilities				1,725,308			2,016,773
Net fair value of derivative instruments - asset (liability)			$	530,443		$	(945,222	)

(1) ~~All~~As ~~other~~of ~~unsettled~~December ~~transactions~~31, ~~excluding~~2010 ~~derivative~~and ~~instruments~~2009, ~~between~~none of the Partnership’s ~~and~~derivative ~~the~~instruments ~~Managing~~were ~~General~~designated ~~Partner~~as hedges.

~~Commencing~~The ~~with~~following ~~the~~table ~~36th~~presents ~~month of well operations,~~ the ~~Managing~~impact General Partner withholds from monthly Partnership cash distributions, amounts to be used to fund statutorily-mandated well plugging, abandonment and environmental site restoration expenditures. A Partnership well may be abandoned, with consent of ~~all non-operators, when depleted or an evaluation is made that~~ the ~~well~~Partnership’s ~~has~~derivative ~~become~~instruments ~~uneconomical~~on ~~to produce. Per-well plugging fees withheld during 2009 and 2008 were $50 per well each month~~ the ~~well produced. The total amount per well, withheld from~~ Partnership’s ~~cash~~accompanying ~~distributions~~statements ~~for the purposes~~ of ~~funding future Partnership obligations, is recorded on the balance sheets in the long-term asset line captioned, “Other Assets~~operations.”

As of December 31, 2008, certain amounts recorded by the Partnership as assets in the account “Due from (to) 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 $1.2 million, from the Managing General Partner.

	Year Ended December 31,
	2010							2009
Statement of operations line item	Reclassification of Realized Gain (Loss) Included in Prior Periods Unrealized			Realized and Unrealized Gain For the Current Period		Total		Reclassification of Realized Gain (Loss) Included in Prior Periods Unrealized			Realized and Unrealized Gain (Loss) For the Current Period			Total

Commodity price risk management, net
Realized gain	$	25,346		$	729,046	$	754,392	$	2,100,436		$	407,996		$	2,508,432
Unrealized (loss) gain		(25,346	)		1,501,011		1,475,665		(2,100,436	)		(1,495,364	)		(3,595,800	)
Total commodity price risk management gain (loss), net	$	-		$	2,230,057	$	2,230,057	$	-		$	(1,087,368	)	$	(1,087,368	)

~~Additionally,~~NOTE ~~certain~~5 ~~amounts representing royalties on Partnership production paid in September 2009 were recorded by the Partnership as liabilities in the account “Due from (to) Managing General Partner~~-~~other,~~ ~~net.” These~~CONCENTRATION ~~amounts,~~OF which totaled approximately $78,000 including legal fees of approximately $7,000, represented the Partnership’s share of the court approved royalty litigation payment and settlement, more fully described in Note 9, Commitments and Contingencies. During September 2009, all settlement costs related to this litigation were paid by the Partnership, to the Managing General Partner.RISK

~~For~~Accounts ~~more~~Receivable. The ~~information~~Partnership’s ~~concerning~~accounts ~~the~~receivable ~~September~~are ~~2009~~from ~~settlement~~purchasers of ~~the~~natural ~~Partnership’s~~gas, NGLs and crude oil production. The ~~tax~~Partnership ~~refund~~sells ~~receivable~~substantially all of its natural gas, NGLs and ~~Colorado~~crude ~~royalty~~oil ~~litigation~~to ~~settlement~~customers ~~liability~~who ~~during~~purchase ~~September~~natural ~~2009~~gas, NGLs and ~~its~~crude ~~related~~oil ~~impact~~from toother partnerships managed by the Partnership’s ~~cash~~Managing ~~distributions~~General ~~for~~Partner. Inherent to the ~~month~~Partnership’s industry is the concentration of ~~September~~natural ~~2009~~gas, ~~see~~NGL ~~Note~~and 6,crude ~~Partners~~oil sales to a few customers. This industry concentration has the potential to impact the Partnership’s ~~Equity~~overall exposure to credit risk, either positively or negatively, in that its customers may be similarly affected by changes in economic and ~~Cash~~financial ~~Distributions~~conditions, commodity prices or other conditions.

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 years ended December 31, 2009 and 2008. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in “Natural gas and oil production costs” on the statements of operations.

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~~Index~~Table Of Contents

PDC 2005-A LIMITED PARTNERSHIP

Notes to Financial Statements

	Year Ended December 31,
	2009		2008
Well operations and maintenance (1)	$	1,199,372	$	1,004,754
Gathering, compression and processing fees (2)		204,242		224,347
Direct costs - general and administrative (3)		442,140		344,410
Cash distributions (4) (5)		1,073,707		1,210,519

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.

~~(1)~~Major Customers. ~~Under~~The ~~the~~following ~~D&O~~table ~~Agreement,~~presents the ~~Managing~~individual ~~General~~customers ~~Partner,~~constituting as10% ~~operator~~or more of ~~the~~total ~~wells, receives payments for well charges and lease operating supplies and maintenance expenses from the Partnership when the wells begin producing~~revenues.

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~~Derivative ~~the~~Counterparties. ~~D&O~~A ~~Agreement,~~significant ~~PDC~~portion ~~provides~~of ~~all~~the ~~necessary~~Partnership’s ~~labor,~~future ~~vehicles,~~liquidity ~~supervision,~~is ~~management,~~concentrated ~~accounting,~~in ~~and~~derivative ~~overhead~~instruments ~~services~~that ~~for~~enable ~~normal~~the ~~production operations, and may deduct from~~ Partnership ~~revenues~~to manage a ~~fixed~~portion ~~monthly~~of ~~charge~~its ~~for~~exposure ~~these services. The charge for these operations and field supervision fees (referred~~ to asprice ~~“well~~volatility ~~tending~~from ~~fees”) for each~~ producing ~~well~~natural isgas ~~based~~and oncrude ~~competitive industry field rates which vary based on areas of operation~~oil. ~~The~~These ~~well~~arrangements ~~tending~~expose ~~fees~~the ~~and~~Partnership ~~administration fees may be adjusted annually~~ to ~~an amount equal to~~ the ~~rates~~risk ~~initially~~of ~~established~~nonperformance by the ~~Drilling~~counterparties. The ~~and~~Managing ~~Operating~~General ~~Agreement~~Partner ~~multiplied~~primarily byuses ~~the~~financial ~~then~~institutions, ~~current~~who ~~average~~are ofalso ~~the~~major ~~Oil~~lenders ~~and~~in ~~Gas Extraction Index and~~ the ~~Professional~~Managing ~~and~~General ~~Technical~~Partner’s ~~Services~~credit ~~Index~~facility agreement, as ~~published~~counterparties byto ~~the~~its ~~United~~derivative ~~States~~contracts. To ~~Department of Labor~~date, ~~Bureau of Labor Statistics, provided that~~ the ~~charge~~Managing ~~may~~General ~~not~~Partner ~~exceed~~has ~~the~~had ~~rate~~no ~~which~~counterparty ~~would~~default ~~be charged by the comparable operators in the area of operations~~losses. ~~This~~The ~~average~~Managing isGeneral ~~commonly~~Partner ~~referred~~has toevaluated as the ~~Accounting~~credit ~~Procedure~~risk ~~Wage~~of ~~Index~~the ~~Adjustment~~Partnership’s ~~which~~derivative isassets ~~published~~from ~~annually~~counterparties byusing ~~the~~relevant ~~Council~~credit ofmarket ~~Petroleum~~default ~~Accountants Societies~~rates, orgiving ~~COPAS. These~~consideration ~~rates~~to ~~are~~amounts ~~reflective~~outstanding offor ~~similar~~each ~~costs~~counterparty ~~incurred~~and bythe ~~comparable~~duration ~~operators~~of ineach ~~the~~outstanding ~~production~~derivative ~~field~~position. ~~PDC,~~The inManaging ~~certain~~General ~~circumstances,~~Partner has ~~and~~determined ~~may~~based inon ~~the~~this ~~future~~evaluation, ~~provided~~that ~~equipment~~the orimpact ~~supplies,~~of ~~performed~~the ~~salt~~nonperformance ~~water~~of ~~disposal services and other services for~~ the ~~Partnership~~counterparties aton the ~~lesser~~fair value of ~~cost~~the orPartnership’s ~~competitive~~derivative ~~prices~~instruments inis ~~the~~not ~~area of operations~~significant.

~~The~~NOTE ~~Managing~~6 ~~General Partner as operator bills non~~-~~routine~~ ~~operations~~ASSET ~~and~~RETIREMENT 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.OBLIGATIONS

The ~~well~~following ~~operating,~~table orpresents ~~well~~the ~~tending,~~changes ~~charges~~in ~~cover~~carrying ~~all~~amounts ~~normal~~of ~~and~~the ~~regularly~~asset ~~recurring~~retirement ~~operating~~obligations ~~expenses~~associated ~~for~~with the ~~production,~~Partnership’s ~~delivery,~~working ~~and~~interest ~~sale~~in of natural gas and crude oil, ~~such as:~~properties.

· well tending, routine maintenance, and adjustment;

	Year Ended December 31,
	2010		2009

Balance at beginning of year	$	512,800	$	381,260
Revisions in estimated cash flows		-		122,571
Accretion expense		27,542		8,969
Balance at end of year	$	540,342	$	512,800

·If ~~reading~~the ~~meters,~~fair ~~recording~~value ~~production,~~of ~~pumping~~the estimated asset retirement obligation changes, ~~maintaining~~an ~~appropriate~~adjustment ~~books~~is ~~and~~recorded ~~records;~~to both the asset retirement obligation and the asset retirement cost.

· 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.

F-15

~~Index~~Table Of Contents

PDC 2005-A LIMITED PARTNERSHIP

Notes to Financial Statements

~~These~~NOTE ~~costs~~7 ~~are charged at the invoice cost of the materials purchased or the third~~-~~party~~ ~~services~~COMMITMENTS ~~performed.~~AND CONTINGENCIES

~~Lease~~Litigation. The ~~Operating~~Company ~~Supplies~~is ~~and~~involved ~~Maintenance~~in ~~Expense. The~~various ~~Managing~~legal ~~General~~proceedings ~~Partner~~that ~~and~~it ~~its~~considers ~~affiliates~~normal ~~may~~to ~~enter~~its ~~into~~business. ~~other~~The ~~transactions~~Company ~~with~~reviews the ~~Partnership~~status ~~for~~of ~~services,~~these ~~supplies~~proceedings ~~and~~on ~~equipment~~an ~~during~~ongoing ~~the~~basis ~~production~~and, ~~phase~~from oftime ~~the~~to ~~Partnership~~time, ~~and~~may issettle ~~entitled~~or tootherwise ~~compensation~~resolve atthese ~~competitive~~matters ~~prices~~on terms and ~~terms~~conditions asthat ~~determined~~management bybelieves ~~reference~~are toin ~~charges~~the ofbest ~~unaffiliated~~interests ~~companies~~of ~~providing~~the ~~similar~~Company. ~~services,~~There ~~supplies~~are ~~and~~no ~~equipment. Management~~assurances ~~believes~~that ~~these~~settlements ~~transactions~~can ~~were~~be reached on acceptable terms noor ~~less~~that ~~favorable~~adverse ~~than~~judgments, ~~could~~if ~~have~~any, ~~been~~in ~~obtained~~the ~~from~~remaining ~~non-affiliated~~litigation ~~third~~will ~~parties~~not be less than or exceed the amounts reserved.

~~(2)~~Royalty Owner Class Action. ~~Under~~On ~~the~~May ~~Agreement~~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 isin ~~responsible~~the ~~for~~District ~~gathering~~Court, ~~compression~~Weld County, ~~processing~~Colorado ~~and~~alleging ~~transporting~~that the Managing General Partner underpaid royalties on natural gas produced from wells operated by the ~~Partnership~~Managing toGeneral ~~interstate~~Partner ~~pipeline~~in ~~systems,~~parts ~~local~~of ~~distribution~~the ~~companies,~~State of Colorado (the “Droegemueller Action”). The plaintiff sought declaratory relief and~~/or~~ ~~end-users~~to inrecover an unspecified amount of compensation for underpayment of royalties paid by the ~~area~~Managing ~~from~~General Partner pursuant to leases. The Managing General Partner moved the ~~point~~case to Federal Court on June 28, 2007. On October 10, 2008, the ~~natural~~court ~~gas~~preliminarily ~~from~~approved a settlement agreement between the ~~well~~plaintiffs isand ~~commingled~~the ~~with~~Managing ~~natural~~General ~~gas~~Partner, ~~from~~on ~~other~~behalf ~~wells~~of itself and the Partnership. InAlthough ~~such~~the Partnership was not named as a ~~case~~party in the suit, the lawsuit states that this action relates to all wells operated by the Managing General Partner, ~~uses~~which ~~gathering~~includes ~~systems~~a ~~already~~majority ~~owned~~of bythe ~~PDC~~Partnership’s wells in the Wattenberg field. For information regarding the number of Partnership wells located in this field, orsee ~~PDC~~Supplemental ~~constructs~~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 ~~necessary~~settlement ~~facilities~~relating ifto nothe ~~such~~Partnership’s ~~line~~wells ~~exists~~for the year ended December 31, 2009 that has been expensed by the Partnership is approximately $5,000 including associated legal costs of approximately $2,000. InThe ~~such~~portion aof ~~case~~the settlement relating to the Partnership’s wells for all periods through December 31, 2009 that has been expensed by the Partnership ~~pays~~is aapproximately ~~gathering~~$78,000 ~~compression~~including ~~and~~associated ~~processing~~legal ~~fee~~costs ~~directly~~of toapproximately $7,000. This entire settlement of $70,954 was deposited by the Managing General Partner atinto ~~competitive~~an ~~rates~~escrow account on November 3, 2008. IfNotice aof ~~third-party~~the ~~gathering~~settlement ~~system~~was ismailed ~~used~~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 ~~pays~~share ~~the~~of ~~gathering~~settlement ~~fee~~costs ~~charged~~were paid by the ~~third-party~~Partnership ~~gathering~~and related required judicial action from the ~~gas~~settlement of the suit was implemented in this distribution.

~~(3)~~ The ~~Managing~~Partnership ~~General Partner~~ is ~~reimbursed~~involved byin ~~the~~various ~~Partnership~~other ~~for~~legal ~~all~~proceedings ~~direct~~that ~~costs~~are ~~expended~~considered bynormal ~~them~~to on the Partnership’s ~~behalf~~business. ~~for~~Although ~~administrative~~the ~~and~~results ~~professional~~cannot ~~fees~~be known with certainty, the Managing General Partner believes that the ultimate results of such asproceedings ~~legal~~will ~~expenses,~~not ~~audit~~have ~~fees~~a ~~and~~material ~~engineering~~effect ~~fees~~on ~~for~~the ~~reserve~~Partnership’s ~~reports~~financial position, results of operations or liquidity.

~~(4) The~~Environmental. Due ~~Agreement~~to ~~provides~~the ~~for~~nature of the ~~allocation~~natural ofgas ~~cash~~and ~~distributions~~crude ~~80%~~oil toindustry, the ~~Investors~~Partnership ~~Partners~~is exposed to environmental risks. The Managing General Partner has various policies and ~~20%~~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. ~~The~~Liabilities ~~Investor~~are ~~Partner~~accrued ~~cash~~when ~~distributions~~environmental ~~during~~assessments ~~2009~~and/or clean-ups are probable and ~~2008~~the ~~include~~costs ~~$44~~can be reasonably estimated. During the year ended December 31,~~848~~ 2010, the Managing General Partner identified existing ground contamination and the Partnership incurred expenses of $1756,~~685~~000 for ground contamination remediation. As of December 31, ~~respectively~~2010, the Partnership accrued environmental remediation liabilities for ~~Investor~~one ~~Partner~~of ~~units~~the ~~repurchased~~Partnership’s bywell ~~PDC.~~pads ~~For~~involving ~~additional~~one ~~disclosure~~well ~~regarding~~in the ~~allocation~~amount of ~~cash distributions~~$5,000 ~~refer~~and tois ~~Note~~included 6in 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, ~~Partners~~2010, which have not been provided for or would otherwise have a material impact on the Partnership’s ~~Equity~~financial ~~and~~statements. However, ~~Cash~~there ~~Distributions~~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.

(5) Distributions to Partners in 2009 were impacted by non-recurring items. See Note 6, Partners’ Equity and Cash Distributions below for detailed information on these transactions.

Note 4 - Fair Value Measurements

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 commodity derivative instruments for New York Mercantile Exchange, or NYMEX, based fixed-price natural gas swaps and collars.

· 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.

F-16

~~Index~~Table Of Contents

PDC 2005-A LIMITED PARTNERSHIP

Notes to Financial Statements

·NOTE ~~Level~~8 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~~PARTNERS’s ~~commodity~~EQUITY ~~derivative~~AND ~~instruments~~CASH ~~for Colorado Interstate Gas, or CIG, based fixed-price natural gas swaps, collars, oil swaps, and natural gas basis protection swaps.~~DISTRIBUTIONS

Derivative Financial Instruments. The Partnership measures fair value 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 valuation determination also gives consideration to nonperformance risk on Partnership liabilities in addition to nonperformance risk on PDCPartners’s own business interests and liabilities, as well as the credit standing of derivative instrument counterparties. For more information concerning the Partnership’s concentration of credit risk and the Managing General Partner’s evaluation of that risk, see Note 7, Concentration of Credit Risk, below.Equity

~~The~~Limited ~~following~~Partner ~~table~~Units. A ~~presents,~~Limited byPartner ~~hierarchy~~unit ~~level,~~represents the individual interest of an individual investor partner in the Partnership’s. No ~~derivative~~public ~~financial~~market ~~instruments,~~exists ~~including~~or ~~both~~will ~~current~~develop ~~and~~for ~~non-current~~the ~~portions~~units. While units of the Partnership are transferable, ~~measured~~assignability atof ~~fair~~the ~~value~~units ~~for~~is limited, requiring the ~~years~~consent ~~ended~~of ~~December~~the 31Managing General Partner. Further, ~~2009~~individual ~~and~~investor ~~2008~~partners may request that the Managing General Partner repurchase units pursuant to the Unit Repurchase Program.

	Level 1			Level 3			Total
As of December 31, 2008
Assets:
Commodity based derivatives	$	-		$	2,816,535		$	2,816,535
Total assets		-			2,816,535			2,816,535
Liabilities:
Basis protection derivative contracts		-			(165,957	)		(165,957	)
Total liabilities		-			(165,957	)		(165,957	)
Net asset	$	-		$	2,650,578		$	2,650,578
As of December 31, 2009
Assets:
Commodity based derivatives	$	520,527		$	551,024		$	1,071,551
Total assets		520,527			551,024			1,071,551
Liabilities:
Commodity based derivatives		(41,267	)		(90,592	)		(131,859	)
Basis protection derivative contracts		-			(1,884,914	)		(1,884,914	)
Total liabilities		(41,267	)		(1,975,506	)		(2,016,773	)
Net asset (liability)	$	479,260		$	(1,424,482	)	$	(945,222	)

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.

	Investor Partners			Managing General 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 12.5% 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 12.5%, with a corresponding decrease to the Managing General Partner. The 12.5% 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. For the years ended December 31, 2010 and 2009, no obligation of the Managing General Partner arose under this provision.

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. As of December 1, 2010, the Managing General Partner suspended the opportunity for an individual non-affiliated Investor Partner to request that PDC repurchase their respective limited partnership units under the terms of the program, pending the outcome of the proposed Merger Agreement.

F-17

~~Index~~Table Of Contents

PDC 2005-A LIMITED PARTNERSHIP

Notes to Financial Statements

~~The~~Cash ~~following table presents the changes of the Partnership’s Level 3 derivative financial instruments measured on a recurring basis:~~Distributions

	December 31,
	2009			2008
Fair value, net asset (liability) beginning of year	$	2,650,578		$	(155,693	)
Changes in fair value included in statement of operations line item:
Commodity price risk management (loss) gain, net		(1,566,628	)		3,038,361
Settlements		(2,508,432	)		(232,090	)
Fair value, net (liability) asset end of year	$	(1,424,482	)	$	2,650,578
Change in unrealized gains (losses) relating to assets (liabilities) still held as of December 31, 2009 and December 31, 2008, respectively, included in statement of operations line item:
Commodity price risk management (loss) gain, net	$	(1,894,127	)	$	-

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 September 2005. The following table presents the cash distributions made to the Investor Partners and Managing General Partner during the years indicated:

See Note 5, Derivative Financial Instruments, for additional disclosure related to the Partnership’s derivative financial instruments.

	Year Ended December 31,
	2010		2009

Cash distributions	$	3,356,120	$	5,144,303

~~Non~~Distributions to Partners in 2009 were impacted by non-~~Derivative~~recurring ~~Assets~~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 $1.2 million. Cash distribution in 2009 to the partners includes $0.4 million paid on the behalf of Investor Partners, to the Internal Revenue Service and ~~Liabilities~~state taxing authorities as a part of a comprehensive settlement agreement with taxing agencies. ~~The~~In ~~carrying~~addition, ~~values~~the Partnership’s payment to the Managing General Partner for royalty settlement costs of approximately $0.1 million decreased distributions in 2009. Both amounts had been previously accrued by the ~~financial~~Partnership ~~instruments~~in ~~comprising~~“Due ~~current~~from ~~assets~~(to) ~~and~~Managing ~~current~~General ~~liabilities~~Partner ~~approximate~~– ~~fair~~other, ~~value~~net.” In ~~due~~2010, distributions to Partners were reduced $60,000 for the ~~short-term~~withholding ~~maturities~~of funds for the Partnership’s future development of ~~these~~proved ~~instruments~~undeveloped reserves.

~~See~~NOTE ~~Note~~9 2-

Year Ended December 31,

Major Customer

Williams Production RMT (“Williams”),

Suncor Energy (USA) Inc. (“Suncor”)

Filing Compare · PDC 2005-A Limited Partnership