UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

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 000-50618

PDC 2003-D Limited Partnership ~~(Exact name of registrant as specified in its charter)~~

(Exact name of registrant as specified in its charter)

West Virginia	56-2348528
(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~~(Address ~~telephone~~of ~~number,~~principal ~~including~~executive ~~area~~offices) (Zip code ~~(303~~) ~~860-5800~~

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 o ¨ No þ

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

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 oþ No þ¨

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 o ¨ No o¨

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. þ

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 o¨ Accelerated filer o¨ Non-accelerated filer o¨ Smaller reporting company þ

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

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 ~~June~~December 3031, 2010, the Partnership had 1,749.84 units of limited partnership interest and no units of additional general partnership interest outstanding.

PDC 2003-D LIMITED PARTNERSHIP

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

		Page
	PART I
	Explanatory Note to This Comprehensive Annual Report	1
	Special Note Regarding Forward-Looking Statements	1
Item 1	Business	2
Item 1A	Risk Factors	17
Item 1B	Unresolved Staff Comments	17
Item 2	Properties	17
Item 3	Legal Proceedings	17
Item 4	[Removed and Reserved]	17
	PART II
Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	18
Item 6	Selected Financial Data	20
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	34
Item 8	Financial Statements and Supplementary Data	34
Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	35
Item 9A(T)	Controls and Procedures	35
Item 9B	Other Information	38
	PART III
Item 10	Directors, Executive Officers and Corporate Governance	39
Item 11	Executive Compensation	43
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	44
Item 13	Certain Relationships and Related Transactions, and Director Independence	44
Item 14	Principal Accountant Fees and Services	46
	PART IV
Item 15	Exhibits, Financial Statement Schedules	47
Signatures		49
Financial Statements		F-1

TABLE OF CONTENTS

Index

		Page
	PART I
Item 1	Business	3
Item 1A	Risk Factors	21
Item 1B	Unresolved Staff Comments	21
Item 2	Properties	21
Item 3	Legal Proceedings	21
Item 4	[Removed and Reserved]	21
	PART II

Item 5	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	22
Item 6	Selected Financial Data	24
Item 7	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 7A	Quantitative and Qualitative Disclosures About Market Risk	37
Item 8	Financial Statements and Supplementary Data	37
Item 9	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	37
Item 9A	Controls and Procedures	37
Item 9B	Other Information	38

	PART III

Item 10	Directors, Executive Officers and Corporate Governance	39
Item 11	Executive Compensation	43
Item 12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	44
Item 13	Certain Relationships and Related Transactions, and Director Independence	44
Item 14	Principal Accountant Fees and Services	46

	PART IV

Item 15	Exhibits, Financial Statement Schedules	47

Signatures		50

Financial Statements		F-1

Table of Contents

PART I

~~Explanatory~~WHERE ~~Note~~YOU toCAN ~~This~~FIND ~~Comprehensive~~MORE ~~Annual Report~~INFORMATION

The PDC 2003-D Limited Partnership (the “Partnership” or the “Registrant”), ~~which~~is ~~was~~subject ~~funded~~to the reporting and ~~commenced~~information ~~operations~~requirements onof ~~December~~the 15Securities Exchange Act of 1934, ~~2003~~as amended, ~~filed~~and is as a ~~Comprehensive~~result ~~Annual~~obligated ~~Report~~to onfile ~~Form~~periodic ~~10-K~~reports, ~~for~~proxy statements and other information with the ~~years~~SEC. The ~~ended~~SEC ~~December~~maintains 31a website that contains the annual, ~~2007~~quarterly, ~~2006~~and current reports, proxy and ~~2005~~information onstatements, ~~October~~and 8other information regarding the Partnership, ~~2010.~~which the Partnership electronically files with the SEC. The ~~report~~address ~~included~~of ~~condensed~~that ~~quarterly~~site ~~unaudited~~is ~~financial~~http://www.sec.gov. The ~~statements~~Central Index Key, or CIK, for ~~each~~the ofPartnership is 0001270430. You can read and copy any materials the ~~applicable~~Partnership ~~quarters~~files inwith ~~2007~~the SEC at the SEC’s Public Reference Room at 100 F Street, ~~2006~~N.E., ~~and~~Room ~~2005~~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.

~~This~~UNITS ~~Comprehensive~~OF Annual Report on Form 10-K for the years ended December 31, 2009 and 2008 is the first periodic report the Partnership has filed with the Securities and Exchange Commission, or SEC, since the filing of the previously mentioned Comprehensive Annual Report on Form 10-K for 2007-2005. The financial information presented in this Annual Report on Form 10-K includes audited financial statements for the years ended December 31, 2009 and 2008 as well as unaudited condensed financial statements for each applicable interim period in 2009 and 2008. The Partnership has not filed Form 10-Qs for the quarterly periods ended March 31 and June 30, 2010.MEASUREMENT

~~Special~~The ~~Note~~following ~~Regarding~~presents ~~Forward-Looking~~a ~~Statements~~list of units of measurement used throughout the document.

~~This~~Bbl ~~Annual~~– ~~Report~~One ~~contains~~barrel ~~“forward-looking” statements within the meaning~~ of ~~Section~~crude ~~27A~~oil ofor ~~the~~NGL ~~Securities Act of 1933~~ (~~the~~Natural ~~“Securities~~Gas ~~Act”~~Liquids) ~~and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”) regarding PDC 2003-D Limited Partnership’s (the “Partnership’s”~~ or ~~the~~42 ~~“Registrant’s”)~~gallons ~~business, financial condition and results~~ of ~~operations.~~liquid ~~Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, is the Managing General Partner of the Partnership~~volume.

~~All~~Bcf ~~statements~~– ~~other~~One ~~than~~billion ~~statements~~cubic offeet 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 ~~and oil production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner’s strategies, plans and objectives~~volume. However, these words 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 and 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:

●Bcfe ~~changes~~– inOne ~~production~~billion ~~volumes,~~cubic ~~worldwide~~feet ~~demand,~~of ~~and commodity prices for~~ natural gas ~~and oil;~~equivalent.

●Btu ~~changes~~– inBritish ~~estimates~~thermal ~~of proved reserves;~~unit.

●BBtu ~~the~~– ~~timing~~One ~~and~~billion ~~extent~~British ofthermal ~~the Partnership’s success in further developing and producing the Partnership’s natural gas and oil reserves;~~units.

●MBbls ~~the~~– ~~Managing~~One ~~General~~thousand ~~Partner’s~~barrels ~~ability~~of tocrude ~~acquire~~oil ~~drilling~~or ~~rig services, supplies and services at reasonable prices;~~NGLs.

●Mcf ~~risks~~– ~~incident~~One tothousand ~~the~~cubic ~~initial~~feet ~~completion, recompletion and operation~~ of natural gas ~~and oil wells;~~volume.

●Mcfe ~~future~~– ~~production~~One ~~and~~thousand ~~development~~cubic ~~costs;~~feet of natural gas equivalent (six Mcf of natural gas equals one Bbl of crude oil or NGL).

●MMBtu ~~the~~– ~~availability~~One ofmillion ~~Partnership~~British ~~future~~thermal ~~cash flows for investor distributions or funding of Well Development Plan activities;~~units.

●MMcf ~~the~~– ~~availability~~One ofmillion ~~sufficient~~cubic ~~pipeline~~feet ~~and other transportation facilities to carry Partnership production and the impact~~ of ~~these~~natural ~~facilities~~gas ~~on price;~~volume.

●MMcfe ~~the~~– ~~effect~~One ofmillion ~~existing~~cubic ~~and~~feet ~~future laws, governmental regulations and the political and economic climate~~ of ~~the~~natural ~~United~~gas ~~States of America, or U~~equivalent.~~S.;~~

● changes in environmental laws and the regulations and enforcement related to those laws;

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

● the effect of natural gas and oil derivatives activities;

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~~Index~~Table of Contents

●SPECIAL ~~conditions~~NOTE inREGARDING ~~the~~FORWARD-LOOKING ~~capital markets; and~~STATEMENTS

●This ~~losses~~report ~~possible~~contains ~~from~~“forward-looking” ~~pending~~statements orwithin ~~future~~the ~~litigation~~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 2003-D 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.

~~Further,~~All ~~the~~statements ~~Partnership~~other ~~urges~~than ~~the~~statements ~~reader~~of tohistorical ~~carefully~~facts ~~review~~included in and ~~consider~~incorporated ~~the~~by ~~cautionary~~reference ~~statements~~into ~~made in~~ this report ~~and~~are ~~the~~forward-looking ~~Partnership’s~~statements. Words ~~other~~such ~~filings~~as ~~with~~“expects”, ~~the~~“anticipates”, ~~SEC~~“intends”, “plans”, “believes”, “seeks”, “estimates” and ~~public~~similar ~~disclosures.~~expressions ~~Readers~~or ~~are~~variations ~~cautioned~~of ~~not~~such towords ~~place~~are ~~undue~~intended ~~reliance~~to onidentify forward-looking statements herein, which ~~speak~~include ~~only~~statements as 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 ~~date~~Managing General Partner’s strategies, plans and objectives. However, these words are not the exclusive means of ~~this~~identifying ~~report~~forward-looking statements herein. Although ~~Other~~forward-looking ~~than~~statements ascontained ~~required~~in ~~under~~this report reflect the ~~securities~~Managing ~~laws~~General Partner's good faith judgment, ~~the~~such ~~Partnership~~statements ~~undertakes~~can noonly ~~obligation~~be based on facts and factors currently known to ~~update~~the ~~any~~Managing General Partner. Consequently, forward-looking statements inare ~~order~~inherently subject to ~~reflect~~risks ~~any~~and ~~event~~uncertainties, orincluding ~~circumstance~~risks ~~occurring~~and ~~after~~uncertainties incidental to the ~~date~~development, production and marketing of ~~this~~natural ~~report~~gas, orNGLs ~~currently~~and ~~unknown~~crude ~~facts~~oil, orand ~~conditions~~actual oroutcomes may differ materially from the ~~occurrence~~results ofand ~~unanticipated~~outcomes ~~events~~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:

~~Item~~· 1.changes ~~Business~~in production volumes, worldwide demand, and commodity prices for natural gas, NGLs and crude oil;

~~General~~· ~~Information~~changes in estimates of proved reserves;

~~The~~· ~~Partnership~~declines ~~is a publically subscribed West Virginia Limited Partnership which owns an undivided working interest~~ in ~~natural gas and oil wells located in Colorado from which~~ the ~~Partnership~~values produces and sells natural gas and oil. The Partnership was organized and began operations in 2003 with cash contributed by limited and additional general partners (collectively, the “Investor Partners”). The Investor Partners own 80% of the Partnership’s ~~capital,~~natural orgas equity interests. PDC, the Managing General Partner, a Nevada Corporation, owns the remaining 20% of the Partnership’s capital, or equity interest. Upon funding, the Partnership entered into a Drilling and ~~Operating~~crude ~~Agreement~~oil ~~(“D&O~~properties ~~Agreement”)~~resulting ~~with the Managing General Partner that governs the drilling and operational aspects of the Partnership. The Partnership expended substantially all of the capital raised~~ in ~~the offering for the initial drilling and completion of the Partnership’s wells.~~impairments;

In· ~~accordance with~~ the ~~Limited~~timing ~~Partnership~~and ~~Agreement~~extent ~~(the “Agreement”), general partnership interests were converted to limited partnership units at the completion~~ of the Partnership’s ~~drilling~~success ~~activities.~~in Afurther ~~limited~~developing ~~partner’s~~and ~~obligation~~producing ~~to the Partnership under West Virginia law is limited to his or her capital contribution.~~reserves;

~~The~~· ~~following~~the ~~table~~Managing ~~presents~~General ~~Partnership~~Partner’s ~~formation~~ability ~~and~~to ~~organizational~~acquire ~~information~~drilling ~~through~~rig ~~the~~services, ~~completion~~supplies ofand ~~the~~services ~~drilling~~at ~~phase~~reasonable ~~on September 29, 2004:~~prices;

			Number of Partner Units
PDC 2003-D Limited Partnership Information	Date	Number of Partners	Additional General Partner Units			Limited Partner Units		Equity Percentage			Amount (millions)
West Virginia Limited Partnership Formation	September 25, 2003
Limited Partnership Termination Date	December 31, 2050
Public Sale of Securities and Funding	December 15, 2003
Investor Partners (1) Unit Cost: $20,000		1,123		1,735.34			14.50		80.00	%	$	35.0
PDC, Managing General Partner									20.00	%		7.6
Total funding												42.6
Syndication costs paid to third-party brokers												(3.7	)
Management Fee Paid to PDC												(0.9	)
Net funding available for drilling activities									100.00	%	$	38.0
Conversion of additional General Partners to Limited Partners	September 29, 2004			(1,735.34	)		1,735.34
Limited Partnership Units after Conversion				-			1,749.84

risks incident to the additional Codell formation development and operation of natural gas and crude oil wells;

~~(1)~~· ~~The~~future ~~Managing~~production General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual investor partner. For more information about the Managing General Partner’s limited partner unit repurchase program 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~~additional ~~Purchases~~Codell offormation ~~Equity~~development 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.costs;

~~The~~· ~~Partnership~~the ~~expects~~availability ~~continuing operations~~ of ~~its natural gas and oil properties until such time the~~ Partnership’s ~~wells~~future ~~are~~cash ~~depleted~~flows orfor ~~becomes~~investor ~~uneconomical~~distributions ~~to produce, at which time that well may be sold~~ or ~~plugged,~~funding ~~reclaimed and abandoned. The Partnership’s maximum term~~ of ~~existence~~additional ~~extends~~Codell ~~through~~formation ~~December~~development 31, 2050, unless dissolved by certain conditions stipulated within the Agreement which are unlikely to occur at this time, or by written consent of the Investor Partners owning a majority of outstanding units at that time.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.;

changes in environmental laws and the regulation and enforcement related 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 disclosures made in this report and the Partnership’s other filings with the SEC. 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.

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~~Index~~Table of Contents

ITEM 1.

BUSINESS

General Information

The Partnership is a publicly subscribed West Virginia Limited Partnership which owns an undivided working interest in natural gas and crude oil wells located in Colorado from which the Partnership produces and sells natural gas, NGLs and crude oil. The Partnership was organized and began operations in 2003 with cash contributed by limited and additional general partners (collectively, the “Investor Partners”) and the Managing General Partner. The Investor Partners own 80% of the Partnership’s capital, or equity interests. PDC, the Managing General Partner, a Nevada Corporation, 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 expended substantially all of the capital raised in the offering for the initial drilling and completion of the Partnership’s wells.

The Managing General Partner may repurchase Investor Partner units, under certain circumstances provided by the Agreement, upon request of an individual investor partner. For more information about the Managing General Partner’s limited partner unit repurchase program 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 natural gas and crude oil properties until such time the Partnership’s wells are depleted or becomes uneconomical to produce, at which time that well may be sold or plugged, reclaimed and abandoned. The Partnership’s maximum term of existence extends through December 31, 2050, unless dissolved by certain conditions stipulated within the 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 ~~acquisition,~~fall ~~within~~of 2010 and extending through the next three years, ~~beginning~~the inacquisition of the ~~fall~~limited ofpartnership ~~2010,~~units (the “Acquisition Plan”) held by Investor Partners of ~~the~~that ~~remaining~~partnership ~~third~~other than PDC or its affiliates (“non-~~party~~affiliated Investor ~~Partner~~Partners”), ~~interests~~ in the limited partnerships ~~which~~that PDC has sponsored, including ~~PDC~~this ~~2003-D Limited~~ Partnership. ( For additional information regarding PDC’s intention to pursue ~~acquisition~~acquisitions of PDC sponsored partnerships, refer to ~~Regulation~~the FD disclosure included in Items 2.02, 7.01 and/or 78.01 of PDC’s ~~Form~~Forms 8-KsK dated March 4, 2010, June 9, 2010, ~~and~~ July 15, 2010 and November 17, ~~which~~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 athe torelated bemerger ~~proposed~~agreement, ~~merger~~and such agreement ~~wherein~~does or will likely contemplate the ~~Partnership~~partnership ~~will~~being ~~merge~~merged with and into a wholly-owned subsidiary of PDC. Each ~~The~~such ~~transaction~~merger will also be subject to, among other things, PDC having sufficient available capital and the approval by a majority of the ~~Investor~~limited ~~Partners’~~partnerships ~~interests,~~units ~~excluding~~held ~~partnership~~by ~~interest~~the ~~owned~~non-affiliated byInvestor ~~PDC,~~Partners of each respective limited partnership. Consummation ~~Should~~of aany ~~purchase offer from PDC be~~ proposed, ~~approved~~merger byof a ~~majority~~PDC ofsponsored ~~the Partnerships’ unaffiliated~~ limited ~~partners,~~partnership ~~and~~under ~~consummated,~~ the ~~purchase~~Acquisition ~~transaction~~Plan ~~would~~will likely result in athe ~~liquidating~~termination ~~cash~~of ~~distribution~~the toexistence ~~all~~of ~~partners~~that partnership and ~~termination~~the right of ~~the~~non-affiliated ~~existence~~Investor ofPartners ~~the~~to ~~Partnership.~~receive ~~There~~a iscash nopayment ~~assurance~~for ~~that~~their ~~any~~limited ~~such~~partnership ~~acquisition~~units ~~will~~in ~~occur~~that partnership.

Business Strategy

The primary objective of the Partnership is the profitable operation of developed Colorado natural gas and 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, natural gas and oil sales.

Initial Development

The Partnership’s Denver-Julesburg (“DJ”) Basin wells are situated in the Wattenberg Field, located north and east of Denver, Colorado. Of the Partnership’s 32 wells drilled in the Wattenberg Field, 29 wells were initially completed and currently produce from the Codell formation. One of these Codell formation wells was also completed and produces from the shallower Niobrara formation. The remaining productive Wattenberg Field well was initially completed and currently produces from the deeper J-Sand formation. The Partnership drilled two Wattenberg Field wells that targeted the J-Sands that were subsequently evaluated as developmental dry holes. 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 in this production rate in the first few years, followed by years of relatively lower declines.

Future Development Opportunities

Additional Codell formation development in the Codell formation of Wattenberg Field wells, which may provide for additional reserve development and natural gas and oil production, is expected to consist of either the J-Sand formation well’s initial fracture treatment and completion of the upper Codell formation sands, or the Codell formation wells’ recompletion of each well’s current production zone. While Codell formation well recompletions generally occur five to ten years after initial well drilling, the initial Codell formation completion of the J-Sand well may occur at any time that funding availability and favorable economics provide so that well resources are optimally recovered. Additional Codell formation development would generally be expected to occur based on a favorable general economic environment and commodity price outlook. The Managing General Partner has the authority to determine whether to recomplete any or all additional Codell formation development activities and to determine the timing of any recompletions. The timing of the development activities can be affected by the desire to optimize the economic return by further developing well resources when commodity prices are at levels to obtain the highest rate of return to the Partnership. The extent and timing of the Partnership’s Wattenberg Field additional Codell formation development 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 or partial development of the Partnership’s wells proves commercially unsuccessful, a reduction in cash distributions may result.

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~~Index~~Table of Contents

AIn ~~recompletion~~December ~~consists~~2010, ofPDC aacquired ~~second~~four ~~fracture~~affiliated ~~treatment~~partnerships: ~~in the same formation originally fractured in the initial completion.~~ PDC ~~and~~2004-A ~~other~~Limited ~~producers have found that the recompletions generally increase the production rate and recoverable reserves of the wells. Historically~~Partnership, ~~the production resulting from~~ PDC’s ~~Codell~~2004-B ~~recompletions~~Limited ~~has been above the modeled economics; however~~Partnership, ~~all~~PDC ~~recompletions~~2004-C ~~have~~Limited ~~not~~Partnership ~~been economically successful~~ and ~~future~~PDC ~~recompletions may not be economically successful. The cost of recompleting a well producing from the Codell formation, or the initial completion of the J~~2004-~~Sand~~D ~~well’s~~Limited ~~undeveloped Codell formation, is generally one third of the cost of a new well~~Partnership. ~~If the recompletion work is performed,~~ PDC ~~will~~purchased ~~charge~~these ~~the~~partnerships ~~Partnership~~ for the ~~direct~~aggregate ~~costs~~amount of ~~recompletions,~~$34.8 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 flowsmillion.

In November 2010, PDC and a wholly-owned subsidiary of PDC entered into separate merger agreements with each of PDC 2005-A Limited Partnership, PDC 2005-B Limited Partnership, and the 2005 Rockies Region Private Limited Partnership (collectively, the “2005 partnerships”). PDC serves as the managing general partner of each of the 2005 partnerships. Definitive proxy statements for each of the 2005 partnerships requesting approval for the applicable merger were mailed to the non-affiliated Investor Partners of the 2005 partnerships on February 7, 2011. Pursuant to each 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 each respective partnership, as well as, the satisfaction of other customary closing conditions, then such partnership will merge with and into a wholly-owned subsidiary of PDC. There is no assurance the partnerships will obtain the necessary approvals from non-affiliated investors. PDC has re-evaluated the merger consideration agreed to in the merger agreements and has proposed to offer supplemental merger consideration to the non-affiliated Investor Partners of the 2005 partnerships in addition to the merger consideration described above. On March 25, 2011, the special meeting of non-affiliated Investor Partners of the 2005 partnerships was adjourned until May 27, 2011. PDC expects to send non-affiliated Investor Partners of the 2005 partnerships a proxy supplement that provides information relating to the increased merger consideration and also includes such Partnership’s 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 each 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 of the 2005 partnerships in late April or early May.

~~Well~~The ~~Development~~feasibility ~~Plan~~and timing of any future purchase offer by PDC to any additional partnership, including this 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 or any potential proposed repurchase offer to any other of PDC’s various public limited partnerships, including this Partnership, should they occur.

~~The~~Business Managing General Partner has developed a plan to initiate the Wattenberg Field wells’ additional Codell development activities during 2011. In October 2010, the Managing General Partner, will begin to withhold funds from distributable cash flows of the Partnership resulting from both current production. The funds retained that are necessary for the Partnership to pay for the additional Codell formation development 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 fully developed, the Partnership will experience a reduction in proved reserves currently assigned to these wells. The Managing General Partner believes that estimated distributable cash flows during the next five years will be sufficient to fund the initial completion of the Codell formation in the J-Sand well and recompletion of wells currently producing from the Codell formation. The Managing General Partner believes that, based on projected additional Codell formation development costs and projected cash withholding, all Partnership development activities will be completed within a five year period. Current estimated costs for the J-Sands well’s initial Codell formation completion and the currently producing Codell formation wells’ recompletion are between $150,000 and $200,000 per well. This Partnership potentially has 28 additional Codell formation development opportunities. Total withholding for these activities from the Partnership’s distributable cash flows is estimated to be between $4.2 million and $5.6 million. The Managing General Partner will re-evaluate the feasibility of commencing these additional Codell formation development activities based on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the development.Strategy

~~Drilling~~The primary objective of the Partnership is the profitable operation of developed Colorado natural gas and ~~Other~~crude ~~Development~~oil ~~Activities~~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, natural gas, NGLs and crude oil sales.

The Partnership’s ~~properties~~business ~~(the~~plan ~~“Properties”)~~going ~~consist~~forward, ofincluding ~~a working interest in~~ the ~~well~~Additional ~~bore~~Codell inFormation ~~each~~Development ~~well~~Plan, ~~drilled~~is byto ~~the~~produce ~~Partnership.~~and ~~The~~sell ~~Partnership drilled 45 development wells (42.5 net) (~~the ~~number~~natural ofgas, ~~gross~~NGLs ~~wells multiplied by the working interest in the wells owned by the Partnership) during drilling operations that began immediately after funding~~ and ~~concluded~~crude inoil ~~January~~from ~~2006 when~~ the ~~last of the~~ Partnership’s ~~43 productive~~ wells, ~~were~~and ~~connected~~ to ~~sales~~make ~~and~~distributions ~~gathering~~to ~~lines.~~the ~~The~~partners ~~Partnership drilled two wells that were subsequently evaluated~~ as ~~developmental~~outlined ~~dry~~in ~~holes. No exploratory drilling activity was conducted on behalf of~~ the Partnership.’s ~~The~~cash 45distribution ~~wells~~policy discussed ~~above~~in ~~are~~Item ~~the~~5, ~~only~~Market ~~wells~~for toRegistrant's beCommon ~~drilled~~Equity, byRelated ~~the~~Stockholder ~~Partnership~~Matters ~~since~~and ~~all~~Issuer Purchases of ~~the~~Equity ~~funds raised in the~~ Securities. Partnership ~~offering~~cash ~~have~~distributions ~~been~~may ~~expended.~~be Inwithheld ~~accordance~~pursuant ~~with~~to the ~~D&O~~Additional ~~Agreement,~~Codell ~~the~~Formation ~~Partnership~~Development ~~paid its proportionate share of the cost of drilling and completing each well as follows:~~Plan.

~~● The leasehold cost of the prospect;~~Operations

●General. When ~~The~~Partnership ~~intangible~~wells were "completed" (i.e., drilled, fractured or stimulated, and all surface production equipment and pipeline facilities necessary to produce the well ~~costs~~were ~~for~~installed) production operations commenced on each well. All Partnership wells are completed, and ~~placed~~production inoperations ~~production;~~are ~~and~~currently being conducted with regard to each of the Partnership’s productive wells.

●PDC, ~~The~~in ~~tangible~~accordance ~~costs~~with the D&O Agreement, is the named operator of ~~drilling~~record of the Partnership’s wells and ~~completing~~may, in certain circumstances, provide equipment and supplies, perform salt water disposal and other services for the ~~partnership~~Partnership. Generally, ~~wells~~equipment and services are sold to the Partnership at the lower of ~~gathering~~cost ~~pipelines~~or ~~necessary~~competitive toprices ~~connect~~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 ~~nearest~~production ~~appropriate~~revenue ~~sales~~for ~~point~~the orcorresponding ~~delivery~~period. In ~~point~~instances when distributable cash flows are insufficient to make full payment, PDC defers the collection of operating expenses until such time as scheduled expenses may be offset against future Partnership distributable cash flows. In such instances, the Partnership records a liability to PDC.

The Partnership’s business plan going forward, including the Well Recompletion Plan, is to produce and sell the natural gas and 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 Recompletion Plan.

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~~Index~~Table of Contents

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

Areas of Operations

The Partnership’s operating areas are profiled as follows:

Wattenberg Field, DJ Basin, Weld County, Colorado. Located north and east of Denver, Colorado, the Partnership’s wells in this field exhibit production histories typical for other wells located in this field with an initial high production rate and relatively rapid decline, followed by years of relatively lower rates of decline and production levels. Although natural gas is the primary hydrocarbon produced, wells also produce NGLs or oil. Of the Partnership’s 32 wells drilled in the Wattenberg Field, 29 wells were initially completed and currently produce from the Codell formation. One of these Codell formation wells was also completed in the shallower Niobrara formation. The remaining productive well was initially completed and currently produces from the deeper J-Sand formation. The Partnership drilled two Wattenberg Field wells that targeted the J-Sands that were subsequently evaluated as developmental dry holes. The Partnership’s development wells in this area are generally 7,000 to 8,000 feet in depth. Well spacing ranges from 20 to 40 acres per well.

Grand Valley Field, Piceance Basin, Garfield County, Colorado. Located near the western border of Colorado, the Partnership’s 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.

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 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.

Natural Gas and Oil Reserves

The Partnership’s gas and oil reserves are located in the United States. The Partnership’s 2009 and 2008 reserve estimates were prepared with respect to reserve categorization, using the definitions then in effect during each year, for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a), as subsequently interpreted by the SEC’s staff interpretations and guidance. The SEC’s Modernization of Oil and Gas Reporting final rule, adopted by the Partnership as of December 31, 2009, prohibited retroactive application of the new oil and gas industry disclosure standards during earlier reporting years. 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 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 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.

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, Modernization of Oil and Gas Reporting.

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~~Index~~Table of Contents

~~Proved~~Drilling ~~reserves are those quantities of natural gas~~ and ~~oil,~~Other ~~which,~~Development 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:Activities

●Natural ~~Proved~~Gas ~~developed~~and ~~reserves~~Crude ~~are~~Oil ~~those~~Properties. The ~~natural~~Partnership’s ~~gas~~properties (the “Properties”) consist of a working interest in the well bore in each well drilled by the Partnership. The Partnership drilled 45 development wells (42.5 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 ~~oil~~concluded ~~quantities~~in ~~expected~~January 2006 when the last of the Partnership’s 43 productive wells were connected to besales ~~recovered~~and ~~from~~gathering ~~currently~~lines. ~~producing~~The ~~zones~~Partnership ~~under~~drilled two wells that were subsequently evaluated as developmental dry holes. No exploratory drilling activity was conducted on behalf of the ~~continuation~~Partnership. The 45 wells discussed above are the only wells to be drilled by the Partnership since all of ~~present~~the ~~operating~~funds ~~methods~~raised in the Partnership offering have been expended.

●The ~~Proved~~following ~~undeveloped~~table ~~reserves,~~presents orthe ~~PUDs~~Partnership’s productive wells by operating field as of December 31, ~~are~~2010 ~~those~~and ~~reserves~~2009. Productive ~~expected~~wells toconsist beof ~~recovered~~producing ~~from~~wells ~~existing~~and wells ~~where~~capable aof ~~relatively~~producing ~~major~~natural ~~expenditure~~gas isand/or ~~required~~NGLs ~~for~~and ~~recompletion~~crude oil in commercial quantities.

The table below presents information as of December 31, 2009 and 2008, regarding the Partnership’s proved reserves by production field, as estimated by Ryder Scott and reviewed and approved by the Managing General Partner. 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 consist entirely of reserves attributable to the Wattenberg Field’s future initial Codell formation completion of the one productive J-Sand well and future recompletions of 27 of the Partnership’s currently producing Codell formation wells. (See Item 1, Business−Business Strategy, Well Development Plan on page 3) For additional information regarding the Partnership’s natural gas and oil reserves see the Supplemental Natural Gas and Oil Information – Unaudited, Net Proved Natural Gas and Oil Reserves that accompanies the financial statements included in this Annual Report. There were no proved undeveloped reserves developed in 2008 or 2009. The changes in these reserves were due to the changes in prices used to value reserves.

	Producing Gas Wells
	2010				2009
Location	Gross		Net		Gross		Net
State of Colorado
Piceance Basin: Grand Valley Field		13.0		12.4		13.0		12.4
Denver-Julesburg (DJ) Basin: Wattenberg Field		30.0		28.6		30.0		28.6
Total Colorado		43.0		41.0		43.0		41.0

Total Productive Wells		43.0		41.0		43.0		41.0

	As of December 31, 2009									As of December 31, 2008
	Oil (MBbl)		Natural Gas (MMcf)		Natural Gas Equivalent (MMcfe)		Percent			Oil (MBbl)		Natural Gas (MMcf)		Natural Gas Equivalent (MMcfe)		Percent
Proved developed
Piceance Basin: Grand Valley Field		4		1,685		1,709		61	%		4		2,369		2,393		71	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		94		550		1,114		39	%		78		495		963		29	%
Total proved developed		98		2,235		2,823		100	%		82		2,864		3,356		100	%
Proved undeveloped
Piceance Basin: Grand Valley Field		-		-		-		0	%		-		-		-		0	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		236		1,546		2,962		100	%		268		2,091		3,699		100	%
Total proved undeveloped		236		1,546		2,962		100	%		268		2,091		3,699		100	%
Proved reserves
Piceance Basin: Grand Valley Field		4		1,685		1,709		30	%		4		2,369		2,393		34	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		330		2,096		4,076		70	%		346		2,586		4,662		66	%
Total proved reserves		334		3,781		5,785		100	%		350		4,955		7,055		100	%

Additional Codell Formation Development 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 “Additional Codell Formation Development Plan”). The Additional Codell Formation Development Plan consists of the Partnership’s refracturing of Wattenberg Field wells currently producing in the Codell formation and the recompletion of Wattenberg Field wells, currently producing in the deeper J-Sand formation, in the shallower Codell formation production zone. Under the Additional Codell Formation Development Plan, the Partnership plans to initiate additional development activities during 2011. Refracturing, or “refracing,” activities consist of a second hydraulic fracturing treatment in a current production zone, while recompletion activities consist of an initial hydraulic fracturing treatment in a new production zone, all within an existing well bore.

InAdditional ~~2009,~~Codell ~~the~~formation ~~SEC~~development ~~published~~of ~~its~~Wattenberg ~~final~~Field ~~rule~~wells, ~~regarding~~which ~~the~~may ~~modernization~~provide offor ~~natural~~additional ~~gas~~reserve development and ~~oil reporting~~production, ~~which~~generally ~~changed~~occurs ~~the~~five ~~December~~to ~~31,~~ten ~~2009~~years ~~valuation~~after ~~price~~initial ~~for~~well ~~in-ground~~drilling ~~natural~~so ~~gas~~that ~~and~~well ~~oil~~ resources, ~~used~~are optimally utilized. This additional Codell formation development would be expected to ~~determine~~occur ~~economically~~based ~~producible~~on ~~natural~~a ~~gas~~favorable general economic environment and ~~oil~~commodity ~~reserve~~price ~~quantities,~~structure. The ~~from~~Managing General Partner has the ~~year-end~~authority ~~single-day~~to ~~pricing~~determine ~~method~~whether ~~that~~to ~~was~~recomplete ~~used~~or refracture the individual wells and to ~~value~~determine the ~~Partnership’s~~timing ~~reserves~~of atany ~~December~~additional ~~31,~~Codell ~~2008~~formation ~~and~~development ~~earlier,~~activity. The totiming aof ~~method~~the ~~which~~additional ~~applies~~development can be affected by the ~~12-month~~desire ~~average~~to ofoptimize the ~~first-day-~~economic return by recompleting or refracturing of- the~~-month~~ ~~price~~wells ~~during~~when ~~each~~commodity ~~month~~prices are at levels to obtain the highest rate of ~~2009~~return to the Partnership. On Anaverage, ~~economically~~the ~~producible~~production ~~quantity~~resulting isfrom ~~one~~PDC's ~~where~~Codell ~~the~~recompletions ~~revenue~~and ~~provided~~refracturings byhave ~~its~~been ~~sale~~at ismodeled ~~reasonably~~economics; ~~likely~~however, toall ~~exceed~~recompletions ~~the~~or ~~cost~~refracturings tohave ~~deliver~~not ~~that~~been ~~quantity~~economically tosuccessful ~~market.~~and ~~For~~similar ~~more~~future ~~information~~recompletion ~~regarding~~or refracturing activities may not be economically successful. If the ~~SEC’s~~additional ~~Modernization~~Codell offormation ~~Oil~~development ~~and~~work ~~Gas~~is ~~Reporting~~performed, ~~adopted~~PDC bywill charge the Partnership atfor ~~December~~the ~~31,~~direct ~~2009,~~costs ~~see~~of ~~Item~~recompletion 7or refracturing, ~~Management’s~~and ~~Discussion~~the Investor Partners and ~~Analysis~~the Managing General Partner will each pay their proportionate share of ~~Financial~~costs ~~Condition~~based ~~and~~on ~~Results~~the ownership sharing ratios of ~~Operations−Critical~~the ~~Accounting~~Partnership ~~Policies~~from ~~and~~funds ~~Estimates:~~retained ~~Recent~~by ~~Accounting~~the ~~Standards~~Managing General Partner from distributable cash flows.

~~Operations~~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 additional Codell formation development 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 or recompleted, the Partnership will experience a reduction in proved reserves currently assigned to these wells. Both the number and timing of the additional Codell formation development activities will be based on the availability of cash withheld from Partnership distributions. The Managing General Partner believes that, based on projected refracturing and recompletion costs and projected cash withholding, all scheduled Partnership additional Codell formation development activity will be completed within a five year period. This Partnership has not begun to withhold funds for this additional Codell formation development as this Partnership has outstanding payables to the Managing General Partner.

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

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~~Index~~Table of Contents

~~PDC,~~Current inestimated ~~accordance~~costs ~~with~~for ~~the~~these ~~D&O~~well ~~Agreement,~~refracturings ~~is the named operator of record of the Partnership’s wells~~ and ~~may,~~recompletions inare ~~certain~~between ~~circumstances~~$175,000 ~~provide equipment~~ and ~~supplies~~$240,000 ~~perform~~per ~~salt~~activity. As ~~water~~of ~~disposal~~December ~~services~~31, ~~and~~2010, ~~other~~this ~~services for the~~ Partnership. ~~Generally,~~has ~~equipment~~scheduled ~~and services are sold~~ to ~~the~~complete ~~Partnership~~29 atadditional ~~the~~Codell ~~lower~~formation ofdevelopment ~~cost~~opportunities. Total orwithholding ~~competitive~~for ~~prices~~these inactivities from the ~~area of operations. The~~ Partnership’s ~~share~~distributable ofcash ~~production~~flows ~~revenue from a given well~~ is ~~burdened~~estimated ~~by and subject~~ to, ~~royalties~~be ~~and~~between ~~overriding~~$5.1 ~~royalties,~~million ~~monthly operating charges, taxes~~ and ~~other~~$7.0 ~~operating costs~~million. The ItManaging isGeneral ~~PDC’s~~Partner ~~practice~~will tocontinually ~~deduct~~evaluate ~~operating~~the ~~expenses~~timing ~~from~~of ~~the~~commencing ~~production~~these ~~revenue~~additional ~~for~~Codell ~~the~~formation ~~corresponding~~development ~~period.~~activities Inbased ~~instances~~on ~~when~~engineering ~~distributable~~data ~~cash~~and ~~flows~~a ~~are~~favorable ~~insufficient~~commodity toprice ~~make~~environment ~~full~~in ~~payment,~~order ~~PDC~~to ~~defers~~maximize the ~~collection~~financial benefit of ~~operating~~the ~~expenses~~additional ~~until~~well ~~such~~development. As ~~time~~of asDecember ~~scheduled~~31, ~~expenses~~2010 ~~may~~and bethrough ~~offset~~February ~~against~~28, ~~future~~2011, ~~Partnership~~no ~~distributable~~funds ~~cash~~have ~~flows.~~been Inwithheld ~~such~~from ~~instances,~~ the Partnership ~~records~~distributions afor ~~liability~~this torecompletion ~~PDC~~and refracturing.

~~The~~Implementation ~~Partnership’s~~of ~~operations~~the ~~are~~Additional ~~concentrated~~Codell inFormation Development Plan would reduce or eliminate Partnership distributions to the ~~Rocky~~Managing ~~Mountain~~General ~~Region~~Partner ~~where~~and ~~weather~~Investor ~~conditions~~Partners while the work is being conducted and ~~time~~paid ~~periods~~for ~~reserved~~through bythe ~~leasehold~~Partnership ~~restrictions~~funds. Depending ~~can~~upon ~~exist~~the level of withholding and ~~limit~~the ~~operational~~results ~~capabilities~~of ~~for~~operations, asit ~~long~~is aspossible ~~six~~that ~~months.~~the ~~Operational~~Managing ~~constraint~~General ~~challenges~~Partner ~~such~~and asInvestor ~~surface~~Partners ~~equipment~~could ~~freezing~~have ~~can~~taxable ~~limit~~income ~~production~~from ~~volumes~~the Partnership without any corresponding distributions in future years. Non-affiliated ~~Increased~~Investor ~~competition~~Partners ~~for~~are ~~oil~~urged ~~field~~to ~~equipment,~~consult ~~services~~a tax advisor to determine all of the relevant federal, ~~supplies~~state and ~~qualified~~local ~~personnel~~tax ~~and~~consequences ~~wildlife~~of ~~habitat~~the ~~protection~~Additional ~~periods~~Codell ~~may~~Formation ~~also~~Development ~~adversely~~Plan. The ~~affect~~above ~~profitability~~discussion ~~and~~is ~~reduce~~not ~~cash~~intended ~~distributions~~as toa ~~the~~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 Additional Codell Formation Development Plan.

~~The~~Proved following table presents the Partnership’s productive wells by operating field as of December 31, 2009 and 2008. Productive wells consist of producing wells and wells capable of producing natural gas and oil in commercial quantities.Reserves

	Producing Gas Wells
	2009				2008
Location	Gross		Net		Gross		Net
State of Colorado
Piceance Basin: Grand Valley Field		13.0		12.4		13.0		12.4
Denver-Julesburg (DJ) Basin: Wattenberg Field		30.0		28.6		30.0		28.6
Total Colorado		43.0		41.0		43.0		41.0
Total Productive Wells		43.0		41.0		43.0		41.0

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 ~~operating~~proved ~~areas~~reserves. As part of the Managing General Partner’s internal control process, the Partnership’s reserves are ~~profiled~~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 ~~follows:~~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.

DJThe ~~Basin,~~Partnership ~~Wattenberg~~utilized ~~Field,~~the ~~Weld~~services ~~County, Colorado. Located north and east~~ of ~~Denver, Colorado, the Partnership’s wells in this field exhibit production histories typical for other wells located in this field with~~ an ~~initial~~independent ~~high~~petroleum ~~production~~engineer, ~~rate~~Ryder ~~and~~Scott ~~relatively rapid decline~~Company, ~~followed by years of relatively lower rates of decline and production levels~~L.P. ~~Although~~(Ryder ~~natural~~Scott), ~~gas~~to isestimate the ~~primary~~Partnership’s ~~hydrocarbon~~2010 ~~produced,~~and ~~many~~2009 ~~wells also produce oil~~reserves. When Ofpreparing the Partnership’'s 32reserve ~~wells~~estimates, ~~drilled in~~ the ~~Wattenberg~~independent ~~Field,~~engineer 29did ~~wells~~not ~~were~~independently ~~initially~~verify ~~completed and currently produce from~~ the ~~Codell~~accuracy ~~formation.~~and ~~One~~completeness of ~~these~~information ~~Codell formation wells was also completed~~ and ~~produces~~data ~~from~~furnished ~~the~~by ~~shallower Niobrara formation. The remaining productive Wattenberg Field well was initially completed and currently produces from~~ the ~~deeper~~Managing ~~J-Sand~~General ~~formation.~~Partner ~~The~~with ~~Partnership~~respect ~~drilled~~to ~~two~~ownership ~~Wattenberg~~interests, ~~Field~~production ~~wells~~volumes, ~~that~~well ~~targeted~~test ~~the~~data, ~~J-Sands~~historical ~~that~~costs ~~were~~of ~~subsequently~~operations ~~evaluated~~and ~~as developmental dry holes. The Partnership’s~~ development, ~~wells~~product inprices, ~~this~~or ~~area~~any ~~are~~agreements ~~generally~~relating ~~7,000~~ to ~~8,000~~current ~~feet~~and infuture ~~depth.~~operations ~~Well~~of ~~spacing~~properties ~~ranges~~and ~~from~~sales 20of ~~to 40 acres per well~~production.

~~Piceance~~The ~~Basin,~~independent ~~Grand~~petroleum ~~Valley~~engineer ~~Field,~~prepared ~~Garfield~~an ~~County,~~estimate ~~Colorado. Located near the western border~~ of ~~Colorado,~~ the Partnership’s 13reserves ~~wells~~ in ~~this~~conjunction ~~field~~with ~~have~~an ~~also~~ongoing ~~exhibited~~review ~~production~~by ~~histories~~the ~~typical~~Managing ~~for~~General ~~other~~Partner’s ~~wells~~engineers. A ~~located~~final incomparison ~~this~~of ~~field~~data ~~with~~was anperformed ~~initial~~to ~~high~~ensure ~~production~~that ~~rate~~the ~~and~~reserve ~~relatively~~estimates ~~rapid~~were ~~decline~~complete, ~~followed~~determined by ~~years~~acceptable ofindustry ~~relatively~~methods ~~lower rates of decline~~ and ~~production~~to ~~levels.~~a ~~These~~level ~~wells generally produce natural gas along with small quantities~~ of ~~oil.~~detail ~~The majority of~~ the ~~Partnership’s~~Managing ~~development~~General ~~wells~~Partner ~~drilled~~deems ~~in the area were drilled directionally from multi-well pads ranging from two to eight or more wells per drilling pad~~appropriate. The ~~primary~~final ~~drilling~~independent ~~targets~~petroleum ~~were~~engineer's ~~multiple~~estimated ~~sandstone~~reserve ~~reservoirs~~report inwas ~~the~~reviewed ~~Mesa Verde formation~~ and ~~well~~approved ~~depth~~by ~~ranges~~the ~~from~~Managing ~~7,000~~General toPartner’s ~~9,500~~engineering ~~feet.~~staff ~~Well~~and ~~spacing is approximately 10 acres per well~~management.

- 7 -

~~Index~~Table of Contents

~~Sale~~The ofprofessional ~~Production.~~qualifications Inof ~~accordance~~the ~~with~~Managing ~~the~~General ~~D&O~~Partner’s ~~Agreement,~~lead ~~PDC~~engineer ~~markets~~primarily ~~the~~responsible ~~natural~~for ~~gas~~overseeing ~~produced~~the ~~from~~preparation of the Partnership’s ~~wells~~reserve ~~primarily~~estimate tomeets ~~commercial~~the ~~end~~standards ~~users,~~of ~~interstate~~Reserves orEstimator ~~intrastate~~as ~~pipelines~~defined orin ~~local~~the ~~utilities~~Standards onPertaining ato ~~competitive basis, under~~ the ~~available~~Estimating ~~terms~~ and ~~prices,~~Auditing ~~generally under contracts with indexed monthly pricing provisions. PDC does not charge an additional fee for the marketing~~ of ~~the~~Oil ~~natural gas~~ and ~~oil~~Gas ~~because~~Reserves ~~these~~Information ~~services~~as ~~are~~promulgated ~~covered~~ by the ~~monthly~~Society ~~well~~of ~~operating~~Petroleum ~~charge~~Engineers. This ~~monthly charge is more fully described in the following Item 1, Business−Reliance on the~~ Managing General Partner, ~~Provisions~~employee ofholds ~~the~~a ~~D&O~~Bachelor ~~Agreement.~~of ~~The~~Science ~~Managing~~degree ~~General~~in ~~Partner~~Petroleum ~~believes~~and ~~these~~Natural ~~contract~~Gas ~~pricing~~Engineering ~~provisions~~and ~~are~~has ~~customary~~over ~~for~~25 ~~the~~years ~~industry.~~of ~~The~~experience ~~sales~~in ~~price~~reservoir ~~for~~engineering. The ~~natural~~individual ~~gas~~is ~~may~~a ~~include~~member ~~revenue~~of ~~from~~ the ~~recovery~~Society of ~~propane~~Petroleum ~~and~~Engineers, ~~butane~~allowing in the ~~gas~~individual ~~stream,~~to asremain ~~well~~current aswith ~~a premium for~~ the ~~typical~~developments ~~high-energy~~and ~~content~~trends ofin the ~~natural gas~~industry. ~~The Partnership’s Wattenberg Field and~~ Further, toduring ~~a lesser extent~~2009, ~~the~~this ~~Grand~~individual ~~Valley~~attended ~~Field~~ten ~~wells~~hours ~~also~~of ~~produce~~formalized ~~oil~~training inrelating ~~addition~~ to ~~natural~~the ~~gas.~~definitions ~~The~~and ~~Managing~~disclosure ~~General~~guidelines ~~Partner~~set isforth ~~currently~~in ~~able~~the toSEC's ~~sell,~~final atrule orreleased ~~near~~January ~~the Partnership’s wells~~2009, ~~all~~Modernization of ~~the~~Oil ~~Partnership’s~~and ~~oil~~Gas ~~production under a purchase contract with a regional petroleum refiner containing monthly pricing provisions~~Reporting. ~~The Partnership does not refine any of its oil production.~~

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

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

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

The table below presents information regarding the Partnership’s estimated proved reserves. Prior to 2010, the Partnership’s NGLs reserves were included in and reported with natural gas reserves, which impacts the comparability of 2010 reserve information to previously reported 2009 reserve information. See 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. The Partnership’s estimated proved undeveloped reserves consist entirely of reserves attributable to the Wattenberg Field’s future initial Codell formation recompletion of one productive J-Sand well and Codell formation refracturing of 28 of the Partnership’s Codell formation wells. (See Item 1, Business−Operations, Drilling and Other Activities-Additional Codell Formation Development 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)		3,028
Crude Oil and Condensate (MBbl)		333
NGLs (MBbl)		124
Total proved reserves (MMcfe)		5,770

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:

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~~Index~~Table of Contents

~~Natural~~Gross ~~Gas and Oil Production, Unit Prices and Costs~~revenues

~~The~~· ~~following~~A ~~table~~12-month ~~presents~~average ~~information~~price ~~regarding~~calculated as the ~~Partnership’s~~unweighted ~~operations~~arithmetic byaverage ~~field:~~of the price on the first day of each month, January through December.

	Year Ended December 31,
	2009		2008
Production (1)
Natural gas (Mcf)
Piceance Basin: Grand Valley Field		301,170		334,750
Denver-Julesberg (DJ) Basin: Wattenberg Field		76,240		87,356
Total Natural Gas		377,410		422,106
Oil (Bbls)
Piceance Basin: Grand Valley Field		1,144		788
Denver-Julesberg (DJ) Basin: Wattenberg Field		14,378		15,619
Total Oil		15,522		16,407
Natural gas equivalent (Mcfe)
Piceance Basin: Grand Valley Field		308,034		339,478
Denver-Julesberg (DJ) Basin: Wattenberg Field		162,508		181,070
Total natural gas equivalent		470,542		520,548
Natural Gas and Oil Sales
Natural gas sales
Piceance Basin: Grand Valley Field	$	798,866	$	2,130,194
Denver-Julesberg (DJ) Basin: Wattenberg Field		330,547		737,162
Total natural gas sales		1,129,413		2,867,356
Oil sales
Piceance Basin: Grand Valley Field	$	49,960	$	67,939
Denver-Julesberg (DJ) Basin: Wattenberg Field		800,305		1,368,251
Total oil sales		850,265		1,436,190
Natural gas and oil sales
Piceance Basin: Grand Valley Field	$	848,826	$	2,198,133
Denver-Julesberg (DJ) Basin: Wattenberg Field		1,130,852		2,105,413
Total natural gas and oil sales	$	1,979,678	$	4,303,546
Average Sales Price (excluding realized gain (loss) on derivatives)
Natural gas (per Mcf)
Piceance Basin: Grand Valley Field	$	2.65	$	6.36
Denver-Julesberg (DJ) Basin: Wattenberg Field		4.34		8.44
Average sales price natural gas, all fields		2.99		6.79
Oil (per Bbl)
Piceance Basin: Grand Valley Field	$	43.67	$	86.22
Denver-Julesberg (DJ) Basin: Wattenberg Field		55.66		87.60
Average sales price oil, all fields		54.78		87.54
Natural gas equivalent (per Mcfe)
Piceance Basin: Grand Valley Field	$	2.76	$	6.48
Denver-Julesberg (DJ) Basin: Wattenberg Field		6.96		11.63
Average sales price natural gas equivalents, all fields		4.21		8.27
Average Production (Lifting) Cost (2) (per Mcfe)
Piceance Basin: Grand Valley Field	$	1.71	$	2.48
Denver-Julesberg (DJ) Basin: Wattenberg Field		1.92		1.43
Average production cost, all fields		1.78		2.11

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.

(1)	Production as shown in the table is 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.

Production and development costs

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

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

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

	As of December 31, 2010
	Natural Gas (MMcf)		NGLs (MBbl)		Crude Oil and Condensate (MBbl)		Natural Gas Equivalent (MMcfe)		Percent
Proved developed
Piceance Basin: Grand Valley Field		1,329		-		3		1,347		58	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		352		27		76		970		42	%
Total proved developed		1,681		27		79		2,317		100	%

Proved undeveloped
Piceance Basin: Grand Valley Field		-		-		-		-		0	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		1,347		97		254		3,453		100	%
Total proved undeveloped		1,347		97		254		3,453		100	%

Proved reserves
Piceance Basin: Grand Valley Field		1,329		-		3		1,347		23	%
Denver-Julesburg (DJ) Basin: Wattenberg Field		1,699		124		330		4,423		77	%
Total proved reserves		3,028		124		333		5,770		100	%

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~~Index~~Table of Contents

~~Definitions~~Production, ~~used~~Sales, ~~throughout~~Prices ~~Item~~and 1,Lifting ~~Business:~~Costs - By Field

●The ~~Bbl~~following –table ~~One~~presents ~~barrel~~information orregarding 42the UPartnership’s production volumes, natural gas, NGLs and crude oil sales, average sales price received and average production cost by field.S Prior to 2010, NGLs were included in natural gas. As ~~gallons~~a ~~liquid~~result ~~volume~~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.

● MBbl – One thousand barrels

	Year Ended December 31,
	2010		2009
Production(1)

Natural gas (Mcf)
Piceance Basin: Grand Valley Field		264,432		301,170
Denver-Julesberg (DJ) Basin: Wattenberg Field		54,345		76,240
Total Natural Gas		318,777		377,410

Crude Oil (Bbl)
Piceance Basin: Grand Valley Field		769		1,144
Denver-Julesberg (DJ) Basin: Wattenberg Field		11,555		14,378
Total Crude Oil		12,324		15,522

NGLs (Bbl)
Denver-Julesberg (DJ) Basin: Wattenberg Field		4,080		-

Natural gas equivalent (Mcfe)
Piceance Basin: Grand Valley Field		269,046		308,034
Denver-Julesberg (DJ) Basin: Wattenberg Field		148,155		162,508
Total natural gas equivalent		417,201		470,542

Natural Gas, NGLs and Crude Oil Sales

Natural gas sales
Piceance Basin: Grand Valley Field	$	929,762	$	798,866
Denver-Julesberg (DJ) Basin: Wattenberg Field		200,470		330,547
Total natural gas sales		1,130,232		1,129,413

Crude oil sales
Piceance Basin: Grand Valley Field	$	47,769	$	49,960
Denver-Julesberg (DJ) Basin: Wattenberg Field		843,135		800,305
Total crude oil sales		890,904		850,265

NGLs sales
Denver-Julesberg (DJ) Basin: Wattenberg Field	$	172,199	$	-

Natural gas, NGLs and crude oil sales
Piceance Basin: Grand Valley Field	$	977,531	$	848,826
Denver-Julesberg (DJ) Basin: Wattenberg Field		1,215,804		1,130,852
Total natural gas, NGLs and crude oil sales	$	2,193,335	$	1,979,678

Average Sales Price (excluding realized gain on derivatives)

Natural gas (per Mcf)
Piceance Basin: Grand Valley Field	$	3.52	$	2.65
Denver-Julesberg (DJ) Basin: Wattenberg Field		3.69		4.34
Average sales price natural gas, both fields		3.55		2.99

Crude Oil (per Bbl)
Piceance Basin: Grand Valley Field	$	62.12	$	43.67
Denver-Julesberg (DJ) Basin: Wattenberg Field		72.97		55.66
Average sales price crude oil, both fields		72.29		54.78

NGLs (per Bbl)
Denver-Julesberg (DJ) Basin: Wattenberg Field	$	42.21	$	-

Natural gas equivalent (per Mcfe)
Piceance Basin: Grand Valley Field	$	3.63	$	2.76
Denver-Julesberg (DJ) Basin: Wattenberg Field		8.21		6.96
Average sales price natural gas equivalents, both fields		5.26		4.21

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

Piceance Basin: Grand Valley Field	$	2.79	$	1.71
Denver-Julesberg (DJ) Basin: Wattenberg Field		3.86		1.92
Average production cost, both fields		3.17		1.78

●(1) ~~Mcf~~Production –is ~~One~~net ~~thousand~~and ~~cubic~~determined ~~feet~~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) ~~Mcfe~~Average –production ~~One~~unit ~~thousand~~costs ~~cubic~~presented ~~feet~~exclude ofthe ~~natural~~effects ~~gas equivalents, based on a ratio~~ of 6ad ~~Mcf~~valorem ~~for~~and ~~each~~severance ~~barrel of oil, which reflect the relative energy content~~taxes.

● MMcf – One million cubic feet

● MMcfe – One million cubic feet of natural gas equivalents

For 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.

Commodity Price Risk Management. The Partnership’s production sold in the spot market and under market index contracts is subject to market price fluctuations. PDC, as Managing General Partner on behalf of the Partnership through the D&O Agreement, uses derivative instruments for a portion of the Partnership’s committed and anticipated natural gas and oil sales to achieve a more predictable cash flow and to reduce exposure to fluctuations in natural gas and oil commodity prices. Since the Partnership manages price risk on only a portion of its future estimated production, future production not covered by derivatives is subject to the full fluctuation of market pricing. The Partnership’s policies prohibit the use of derivative financial instruments for speculative purposes and permit utilization of derivatives only if there is an underlying physical position. For more information on the Partnership’s derivative financial instruments, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations−Commodity Price Risk Management, Net and Liquidity and Capital Resources.

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.

● Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty.

● Swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty.

● Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG basis protection swaps, which traditionally have negative differentials to NYMEX, PDC, as Managing General Partner, receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. If the index price and contract price are the same, no payment is due to or from the counterparty.

- 10 -

~~Index~~Table of Contents

~~Historically,~~For ~~the~~more ~~Partnership~~information ~~participated~~concerning ~~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~~costs, ~~the~~which ~~allocation~~include ofseverance ~~derivative~~and ~~positions~~ad ~~between~~valorem ~~PDC’s~~taxes ~~corporate~~as ~~interests~~reflected ~~and~~in the Partnership,’s ~~changed~~statements onof aoperations ~~pro-rata~~accompanying ~~basis.~~this ~~Effective September 30~~report, ~~2008,~~see ~~PDC~~Item 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 307, ~~2008, specific designations of the quantities between the Managing General Partner~~Management’s ~~corporate~~Discussion ~~interests~~ and ~~each~~Analysis ~~sponsored~~of ~~drilling~~Financial ~~partnership,~~Condition ~~including this Partnership, were allocated~~ and ~~fixed~~Results atof ~~the~~Operations 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~~this ~~transactions initiated by the Managing General Partner~~report.

~~All~~Natural ~~derivative assets and liabilities are recorded on the balance sheets at fair value. PDC~~Gas, asNGLs ~~Managing General Partner, has elected not to formally designate any of the Partnership’s derivative instruments as hedging instruments~~ and ~~therefore,~~Crude ~~the~~Oil 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.Sales

In accordance with the D&O Agreement, PDC markets the natural gas, NGLs and crude oil produced from the Partnership’s wells primarily to other gas marketers, utilities, industrial end-users and other wholesale gas purchasers. 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, 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 well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. As a result, the Partnership’s revenues from the sale of natural gas, holding production volume constant, increase as market prices increase and decrease as market prices decline. 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 general, the Managing General Partner 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 wells in the Partnership’s Wattenberg Field and, to a significantly lesser extent, the Grand Valley Field wells, produce crude oil as well as natural gas and NGLs. 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.

Transportation and Gathering

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

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Table of Contents

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. natural gas, NGLs and crude 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.

~~Competitive~~Commodity ~~Market~~Price ~~Position~~Risk Management Activities

~~Competition~~The isManaging ~~high~~General ~~among~~Partner, ~~persons~~on ~~and~~behalf ~~companies~~of ~~involved in~~ the ~~exploration~~Partnership ~~and production of natural gas and oil. Because there are thousands of natural gas and oil companies~~ in ~~the~~accordance ~~United~~with ~~States,~~ the ~~national~~D&O ~~supply of natural gas~~Agreement, ~~including~~utilizes ~~the~~commodity ~~Rockies~~based ~~Region~~derivative ~~which~~instruments ~~currently~~to ~~supplies~~manage ~~approximately~~a ~~22%~~portion of the ~~U.S. natural gas production annually, is diversified. The~~ Partnership’s ~~believes~~exposure ~~that~~to ~~the~~price ~~drilling~~volatility ~~and~~with ~~production~~regard ~~capabilities~~to ~~and~~ the ~~experience of the Managing General Partner~~Partnership’s ~~management~~natural gas and ~~professional~~crude ~~staff~~oil ~~generally enables the Partnership to compete effectively~~sales. The ~~During~~financial ~~the~~instruments ~~three~~generally ~~years~~consist ~~preceding~~of ~~2008~~collars, ~~the~~swaps ~~industry~~and ~~generally~~basis ~~experienced~~swaps ~~increasingly~~and ~~stronger~~are ~~demand~~NYMEX-traded ~~for drilling services~~ and ~~supplies~~Colorado ~~that~~Interstate ~~resulted~~Gas, inor ~~year-to-year~~CIG, ~~operating~~based ~~cost increases~~contracts. The ~~This~~Managing ~~trend~~General ~~continued~~Partner ~~through~~may ~~the~~utilize ~~first~~derivatives ~~three~~based ~~quarters~~on ofother ~~the~~indices ~~2008.~~or Asmarkets awhere ~~result~~appropriate. The ofcontracts ~~the~~economically ~~well-publicized~~provide ~~turmoil~~price instability ~~the~~for ~~financial~~committed and ~~commodity~~anticipated ~~markets~~natural ingas ~~late 2008, resultant industry slowdown throughout 2009~~ and ~~the~~crude ~~Managing~~oil ~~General Partner’s cost reduction initiatives~~sales, ~~the~~generally ~~Partnership~~forecasted ~~experienced~~to ~~overall~~occur ~~reductions~~within inthe ~~its~~next ~~2009~~two ~~natural~~to ~~gas~~four-year ~~and oil production costs~~period. The ~~For~~Partnership’s ~~more~~policies ~~information~~prohibit onthe ~~natural~~use ~~gas~~of ~~and~~commodity ~~oil~~derivatives ~~pricing~~for ~~during~~speculative ~~2009~~purposes and ~~2008,~~permit ~~see~~utilization ~~Item 7, Management’s Discussion and Analysis~~ of ~~Financial~~derivatives ~~Condition~~only ~~and~~if ~~Results~~there ofis ~~Operations−Natural~~an ~~Gas~~underlying ~~and~~physical ~~Oil Production Costs~~position. The ~~Partnership~~Managing ~~believes~~General ~~that~~Partner itmanages ~~can~~price ~~compete~~risk ~~effectively~~on inonly ~~its~~a ~~area~~portion of ~~operations. Nevertheless,~~ the Partnership’s ~~results~~anticipated ofproduction, ~~operations~~so ~~and~~the ~~distributable~~remaining ~~cash~~portion ~~flows~~of ~~could~~the bePartnership’s ~~materially~~production ~~adversely~~is ~~affected~~subject byto the ~~uncertainty~~full influctuation ~~ascertaining the ultimate depth and duration~~ of ~~the~~market ~~current economic environment~~pricing.

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

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~~Index~~Table of Contents

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.

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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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.

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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.

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.

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

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

Industry Regulation

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

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

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

Several bills in Congress, if passed, would establish a "cap and trade" system regarding greenhouse gas emissions. Companies would be assigned emission "allowances" under these bills which would decline each year. In addition, new EPA greenhouse gas monitoring and reporting regulations may affect the Partnership and the third parties that process the Partnership’s natural gas, NGLs and crude oil.

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

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

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 or recompletion 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 natural gas and crude oil. Because there are thousands of natural gas and crude oil companies in the United States, the national supply of natural gas, including the Rockies Region which currently supplies approximately 22% of the U.S. natural gas production annually, is diversified. The Partnership believes that the drilling and production capabilities and the experience of the Managing General Partner’s management and professional staff generally enables the Partnership to compete effectively. As a result of the well-publicized turmoil in the financial and commodity markets in late 2008, resultant industry slowdown throughout 2009 and the Managing General 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 its area of operations. Nevertheless, the Partnership’s results of operations and distributable cash flows could be materially adversely affected by the uncertainty in ascertaining the ultimate depth and duration of the current economic environment.

As a result of Federal Energy Regulatory Commission, or FERC, and Congressional deregulation of natural gas and crude oil prices in the past, prices are generally determined by competitive supply-and-demand market forces. The marketing of natural gas, NGLs and crude oil produced by the Partnership is affected by a number of factors, some of which are beyond the Partnership's control and the exact effect of which cannot be accurately predicted. These factors include the volume and prices of crude oil imports, the availability and cost of adequate natural gas and crude oil pipeline and other transportation facilities, the marketing of competitive fuels, such as coal, nuclear and renewable fuel energy and other matters affecting the availability of a ready market, such as fluctuating supply and demand. Among other factors, the supply and demand balance of natural gas and crude oil in world markets combined with supply and demand balance within and across U.S. geographical regions may have caused significant variations in the prices of these traditional hydrocarbon products over recent years.

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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 natural gas, NGLs and crude oil from the Partnership’s wells at locally competitive prices.

The Partnership’s secondary hydrocarbon product is oil. In contrast to U.S. natural gas pricing, which is determined more directly by North American supply-demand factors, crude oil pricing is subject to global supply-demand influences including the presence of the Organization of Petroleum Exporting Countries, or OPEC, whose members establish prices and production quotas for petroleum products of OPEC members from time to time. 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 natural gas and crude oil wells in which the Partnership owns an interest, including the initial drilling, testing, completion, and equipping of wells; subsequent additional Codell formation development, where economical, and ultimate evaluation for abandonment. Further, ~~while~~ the Partnership has the right to take in-kind and separately dispose of its share of all natural gas, NGLs and crude oil produced from the Partnership’s wells. The Partnership designated PDC as its natural gas, NGLs and crude oil production marketing agent and authorized PDC to enter into and bind the Partnership, under those agreements PDC deems in the best interest of the Partnership, in the sale of the Partnership’s natural gas, NGLs and crude oil. Generally, PDC has limited liability to the Partnership for losses sustained or liabilities incurred, except as may result from the operator’'s gross or willful negligence or misconduct. PDC may subcontract certain functions as operator for Partnership wells but retains responsibility for work performed by subcontractors. The D&O Agreement remains in force as long as any well or wells produce, or are capable of economic production, and for an additional period of 180 days from cessation of all production or until PDC is replaced as Managing General Partner as provided for in the D&O Agreement.

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

Under the D&O Agreement, PDC provides all necessary labor, vehicles, supervision, management, accounting, and overhead services for normal production operations and may deduct from Partnership revenues a fixed monthly charge for these services. The charge for these operations and field supervision fees (referred to as “well tending fees”) for each producing well is based on competitive industry field rates which vary based on areas of operation. The well tending fees and administration fees may be adjusted annually to an amount equal to the rates initially established by the D&O Agreement multiplied by the then current average of the Oil and Gas Extraction Index and the Professional and Technical Services Index, as published by the United States Department of Labor, Bureau of Labor Statistics, provided that the charge may not exceed the rate which would be charged by the comparable operators in the area of operations. This average is commonly referred to as the Accounting Procedure Wage Index Adjustment which is published annually by the Council of Petroleum Accountants Societies, or COPAS. These rates are reflective of similar costs incurred by comparable operators in the production field. PDC, in certain circumstances, has and may in the future, provide equipment or supplies, perform salt water disposal services or other services for the Partnership at the lesser of cost or competitive prices in the area of operations.

-Operating 13Hazards and Insurance. The Partnership's production operations include a variety of operating risks, including but not limited to fire, explosions, blowouts, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as gas leaks, ruptures and discharges of natural gas. The occurrence of any of these could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. The Partnership’s gathering and distribution operations are subject to the many hazards inherent in the industry. These hazards include damage to wells, pipelines and other related equipment, damage to property caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

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

Insurance. The Partnership’s production operations involve 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 gas which could result in environmental damage and clean-up obligations. 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, additional Codell formation development and reworks and ongoing productions operations. However, there can be no assurance that this insurance will be adequate to cover all losses or exposure for liability and thus, the occurrence of a significant event not fully insured against, could materially adversely affect Partnership operations and financial condition. Furthermore, the Partnership is not insured against economic losses resulting from damage or destruction to third party property, such as the Rockies Express pipeline; such an event could result in significantly lower regional prices or the Partnership’s inability to deliver natural gas. As of the date of this filing, the Managing General Partner has no knowledge that such events have occurred.

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Table of Contents

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 natural gas and 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.

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

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Index

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 oil industry. These multi-faceted regulations significantly enhance requirements regarding natural gas and oil permitting, environmental requirements and wildlife protection. Permitting delays and increased costs could result from these final regulations. Other potential or recently enacted laws and regulations affecting the Partnership include the following:

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

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

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

i. The Dodd-Frank Act may decrease 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 few completed Codell formation development 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.

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Index

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 additional Codell formation development costs and ongoing level of natural gas and oil production costs.

Partnership expenses relating to preserving the environment have risen during the period covered by this report (2009-2008) and are expected, as a consequence of the factors described above, to continue to rise in 2010 and beyond. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon natural gas and oil wells. While environmental regulations have had no materially adverse effect on the Partnership’s 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 results of operations or distributable cash flows. See Note 9, Commitments and Contingencies, Stormwater Permit.

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.

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 0001270430. 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.

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Index

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.

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Table of Contents

Item 1A.

Risk Factors

Not ~~Applicable~~applicable.

Item 1B.

Unresolved Staff Comments

None.

~~Item~~ITEM 2. ~~Properties~~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~~ITEM 3. ~~Legal~~LEGAL ~~Proceedings~~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. [~~Removed~~REMOVED ~~and~~AND ~~Reserved~~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 ~~June~~December 3031, 2010, the Partnership had 1,~~227~~223 Investor Partners holding 1,749.84 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 ~~June~~December 3031, 2010, the Managing General Partner has repurchased 4143.8490 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 their 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 may have to hold his or her partnership interests indefinitely and 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 distributable cash to the Investor Partners, including any Investor Partner units purchased by the Managing General Partner, and 20% of 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.

~~Cash~~PDC ~~Distribution~~cannot ~~Policy.~~presently ~~PDC~~predict ~~plans~~amounts toof ~~make~~future cash distributions, ofif any, from the Partnership. However, ~~cash~~PDC onexpressly aconditions ~~monthly~~any ~~basis,~~and ~~but~~all nofuture ~~less~~cash ~~often~~distributions ~~than~~upon ~~quarterly,~~the ~~subject~~Partnership tohaving ~~funds~~sufficient ~~being~~cash available for distribution. Sufficient ~~PDC~~cash ~~will~~available ~~make~~for distribution is defined generally as cash ~~distributions~~generated ofby ~~80%~~the Partnership in excess of ~~distributable~~the ~~cash~~amount the Managing General Partner determines is necessary or appropriate to provide for the ~~Investor~~conduct ~~Partners~~of the Partnership's business, ~~including~~to ~~any~~comply ~~Investor~~with ~~Partner~~applicable ~~units~~law, ~~purchased~~to bycomply ~~the~~with ~~Managing~~any ~~General~~other ~~Partner,~~agreements ~~and~~or ~~20%~~to ofprovide ~~distributable~~for ~~cash~~future distributions to ~~the~~unit ~~Managing~~holders. In ~~General~~this ~~Partner~~regard, ~~throughout~~PDC reviews the ~~term~~accounts of the Partnership. ~~Cash~~at isleast ~~distributed~~quarterly tofor the ~~Investor~~purpose ~~Partners~~of ~~and~~determining ~~PDC~~the ~~currently~~sufficiency asof adistributable ~~return~~cash available for distribution. Amounts will be paid to Investor Partners only after payment of ~~capital~~fees inand expenses to the ~~same~~Managing ~~proportion~~General asPartner ~~their~~and ~~proportional~~its ~~interest~~affiliates inand ~~the~~only ~~net~~if ~~income~~there ofis ~~the~~sufficient ~~Partnership~~cash available.

PDC cannot presently predict amounts of future cash distributions, if any, from the Partnership. However, PDC expressly conditions any and all future cash distributions upon the Partnership having sufficient cash available for distribution. Sufficient cash available for distribution is defined generally 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. 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~~Additional Codell Formation Development Plan would reduce or eliminate Partnership cash distributions to investors while the work is being conducted and paid for. All funds withheld for the Additional Codell Formation Development 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 Additional Codell Formation Development 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 Additional Codell Formation Development 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 ~~the~~ 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~~Additional Codell Formation Development Plan see Item 1, Business~~−Future~~ ~~Development~~– ~~Opportunities~~Operations, Drilling and ~~Well~~Other Activities - Additional Codell Formation Development Plan. For ~~and~~ additional information regarding PDC’s disclosed partnership acquisition intensions, ~~see~~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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~~Index~~Table of Contents

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~~Additional Codell Formation Development Plan and any potential merger. The above discussion is not intended as a substitute for careful tax planning, and ~~third~~non-~~party~~affiliated Investor Partners should depend upon the advice of their own tax advisors concerning the effects of the ~~Well~~Additional Codell Formation Development Plan and any potential merger.

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

Period	Cash Distributions
For the year ended December 31, 2009	$	3,631,694
For the year ended December 31, 2010	$	1,246,773
For the year ended December 31, 2008		3,280,728
For the year ended December 31, 2009		3,631,694
For the period from the Partnership’s inception to December 31, 2009	$	28,703,614
For the period from the Partnership's inception to December 31, 2010	$	29,950,387

The volume and rate of production from producing 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 natural gas, NGLs and crude oil production, or significant increases in the production of natural gas, NGLs and crude oil from the successful additional Codell formation development of these properties, if any. The funds necessary for any additional Codell formation development would 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 would then decrease. For more information regarding the additional Codell formation development of the Partnership’s Wattenberg Field wells see Item 1, Business−~~Business Strategy~~Operations, ~~Future~~Drilling and Other Development ~~Opportunities~~Activities -Additional Codell Formation Development Plan on page 36. 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 Repurchase 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 “~~publically~~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.

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~~Index~~Table of Contents

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:

Unit repurchase program period	Units Repurchased During Month Ended		Average Price Paid per Unit
Period	Total Number of Units Repurchased		Average Price Paid perUnit
March 1−31, 2008		1.50	$	4,490
October 1−31, 2010		0.25	$	3,280
April 1−30, 2008		0.25		4,380
November 1−30, 2010		-		-
July 1−31, 2008		0.25		4,580
December 1−31, 2010		0.54		3,285
October 1−31, 2008		11.25		5,218
Total fourth quarter Unit Repurchase Program repurchases		0.79
January 1−31, 2009		10.00	$	5,854
February 1−28, 2009		2.50		5,884
July 1−31, 2009		0.50		5,310
August 1−31, 2009*		3.50		4,930

*ThereITEM ~~were~~6. noSELECTED ~~units~~FINANCIAL ~~repurchased by the Managing General Partner after August 31, 2009 through December 31, 2009.~~DATA

~~Item~~Not 6applicable. ~~Selected Financial Data~~

~~Not~~ITEM ~~applicable~~7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~Item~~The 7.following ~~Management~~discussion and analysis, as well as other sections in this Form 10-K, should be read in conjunction with the Partnership’s ~~Discussion~~accompanying financial statements and ~~Analysis~~related ofnotes ~~Financial~~to ~~Condition~~the ~~and~~financial ~~Results~~statements included in this report. Further, the Partnership encourages the reader to revisit the Special Note Regarding Forward-Looking Statements on page one of ~~Operations~~the report.

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 1 of the report.

PDC Sponsored Drilling Program Acquisition Plan

PDC, the managing general partner of various public limited partnerships, has disclosed its intention to pursue the acquisition, within the next three years beginning in the fall of 2010, of the remaining third-party Investor Partner interests in the limited partnerships which PDC has sponsored, including PDC 2003-D Limited Partnership. (For additional information regarding PDC’s intention to pursue acquisition of PDC sponsored partnerships, refer to Regulation FD disclosure included in Items 2.02 and/or 7.01 of PDC’s Form 8-Ks dated March 4, 2010, June 9, 2010 and July 15, 2010, which 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 offer will be subject to the terms and conditions of a to be proposed merger agreement wherein the Partnership will merge into PDC. The transaction will also be subject to PDC having sufficient available capital and the approval by a majority of the Investor Partners’ interests, excluding partnership interest owned by PDC, of each respective limited partnership. Should a purchase offer from PDC be proposed, approved by a majority of the Partnerships’ unaffiliated limited partners, and consummated, the purchase transaction would result in a liquidating cash distribution to all partners and termination of the existence of the Partnership. There is no assurance that any such acquisition will occur.

Partnership Overview

PDC 2003-D Limited Partnership engages in the development, production and sale of natural gas, NGLs and crude oil. The Partnership began natural gas and crude oil operations in December 2003 and ~~currently~~ operates 43.0 gross (41.0 net) productive wells located in the Rocky Mountain Region in the state of Colorado. The Partnership drilled two wells (1.5 net wells) that were previously determined to be developmental dry holes. 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 ~~may~~tend to be affected by demand factors with a seasonal component.

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Index

Well Development Plan

The Partnership’s wells will produce until they are depleted or until they are uneconomical to produce; however, the Managing General Partner has established a Well Development Plan for the Codell formation of the Partnership’s Wattenberg Field wells that may provide for additional reserve development and production. Additional Codell formation development is expected to consist of either the J-Sand formation well’s initial fracture treatment and completion of the upper Codell formation sands, or the Codell formation wells’ recompletion of each well’s current production zone. While Codell formation well recompletions generally occur five to ten years after initial well drilling, the initial Codell formation completion of the J-Sand well may occur at any time that funding is available so that well resources are optimally recovered and would generally be expected to occur within a favorable general economic environment and commodity price outlook. The Managing General Partner has developed a plan to initiate additional development activities during 2011. See Item 1, Business−Future Development Opportunities and Well Development Plan for more information about the additional Codell formation development and the Managing General Partner’s plan.

Implementation of the Well Development Plan would reduce or eliminate Partnership distributions to investors while the work is being conducted and paid for. 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 the future. Investor Partners are urged to consult a tax advisor to determine all of the relevant federal, state and local tax consequences of the Well Development Plan. The above discussion is not intended as a substitute for careful tax planning, and third-party Investor Partners should depend upon the advice of their own tax advisors concerning the effects of the Well Development Plan.

2009 and 2008 Partnership Overview

The year 2008 was a year of significant events: natural gas and oil prices reached record and near record highs, respectively, through July. Then, in the midst of U.S. credit turmoil and a worldwide economic slump in December 2008, oil prices fell to their lowest in the four year period while natural gas prices decreased approximately 50%. Although natural gas prices rebounded in the last two months of 2009 from earlier in the year, the Partnership overall, experienced substantially lower natural gas and oil commodity pricing in 2009 compared to 2008 as a consequence of the protracted economic recession and ensuing uncertainty in the timing of ongoing economic recovery.

Natural gas and oil sales totaled $2.0 million during 2009 compared to $4.3 million during 2008. This decrease was driven primarily by a depressed commodity price environment. The average sales price per Mcfe, excluding the impact of realized derivative gains, was $4.21 for 2009 compared to $8.27 for the previous year, a decline of 49%. The Partnership’s production decreased to 471 MMcfe for the 2009 annual period compared to 521 MMcfe for the same 2008 period, a decrease of 10%. Period-to-prior-year period production declines are expected declines that naturally take place over a natural gas and oil well’s production life cycle.

While the significant declines in commodity prices have negatively impacted the Partnership’s results of operations for 2009, 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 reasonably successful. Realized derivative gains from natural gas and oil sales contributed an additional $3.04 per Mcfe, or $1.4 million, and $0.25 per Mcfe, or $0.1 million, to 2009 and 2008 total revenues, respectively. Comparatively, the total per Mcfe price realized, consisting of the average sales price and realized derivative gains, decreased 15% to $7.25 during 2009 from $8.52 during the prior year. Although the Partnership’s 2009 natural gas and sales revenues declined by 54%, or $2.3 million compared to 2008, the Partnership’s annual cash flows provided by operating activities increased by $0.4 million, benefited by the previously mentioned Partnership increase in realized derivative gains for the 2009 annual period and the $0.5 million increase in Due from Managing General Partner−other cash receipts.

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Index

Results of Operations

Summary Operating Results

The following table presents selected information regarding the Partnership’s results of operations:

	Year Ended December 31,
	2009		2008			Change
Number of producing wells (end of period)		43		43			-
Production (1)
Natural gas (Mcf)		377,410		422,106			-11	%
Oil (Bbl)		15,522		16,407			-5	%
Natural gas equivalents (Mcfe) (2)		470,542		520,548			-10	%
Mcfe per day		1,289		1,426
Natural Gas and Oil Sales
Natural gas	$	1,129,413	$	2,867,356			-61	%
Oil		850,265		1,436,190			-41	%
Total natural gas and oil sales	$	1,979,678	$	4,303,546			-54	%
Realized Gain (Loss) on Derivatives, net (3)
Natural gas	$	1,131,076	$	182,181			*
Oil		298,681		(51,027	)		*
Total realized gain on derivatives, net	$	1,429,757	$	131,154			*
Average Selling Price (excluding realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	2.99	$	6.79			-56	%
Oil (per Bbl)		54.78		87.54			-37	%
Natural gas equivalents (per Mcfe)		4.21		8.27			-49	%
Average Selling Price (including realized gain (loss) on derivatives)
Natural gas (per Mcf)	$	5.99	$	7.22			-17	%
Oil (per Bbl)		74.02		84.43			-12	%
Natural gas equivalents (per Mcfe)		7.25		8.52			-15	%
Average Lifting Cost (per Mcfe) (4)	$	1.96	$	2.65			-26	%
Operating costs and expenses:
Direct costs - general and administrative	$	82,202	$	58,441			41	%
Depreciation, depletion and amortization	$	2,062,991	$	1,639,101			26	%
Cash distributions	$	3,631,694	$	3,280,728			11	%

* Percentage change not meaningful, equal to or greater than 250% or not calculable. Amounts may not calculate due to rounding.

(1) Production is determined by multiplying the gross production volume of properties in which we have an interest by the average percentage of the leasehold or other property interest the Partnership owns.

(2) A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one Bbl of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcf of natural gas.

(3) Amounts represent realized derivative gains (losses) related to natural gas and oil sales.

(4) Production costs represent natural gas and oil operating expenses which include production taxes.

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Index

Definitions used throughout Management’s Discussion and Analysis of Financial Condition and Results of Operations.

● Bbl – One barrel or 42 U.S. gallons liquid volume

● MBbl – One thousand barrels

● Mcf – One thousand cubic feet

● MMcf – One million cubic feet

● Mcfe – One thousand cubic feet of natural gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, which reflects the relative energy content

● MMcfe – One million cubic feet of natural gas equivalents

● MMbtu – One million British Thermal Units

Natural Gas and Oil Sales

The table below shows sales and production information for each quarter for the years ended December 31, 2009 and 2008. Natural gas and oil sales exclude the impact of commodity-based derivatives, which are reflected in the line “Commodity price risk management, net” in the statements of operations. (In thousands except for per Mcf, per Bbl and per Mcfe amounts and percentage changes).

	2009									2008
Total	Sales (in thousands)			MMcfe			per Mcfe			Sales (in thousands)		MMcfe		per Mcfe
Jan-Mar	$	412		$	110		$	3.78		$	1,248		144	$	8.64
Apr-Jun		455			125			3.63			1,342		124		10.86
Jul-Sept		503			124			4.06			1,171		127		9.25
Oct-Dec		610			112			5.43			543		126		4.31
Total	$	1,980			471		$	4.21		$	4,304		521	$	8.27
Change (year over year)		-54	%		-10	%		-49	%

	2009									2008
Natural Gas	Sales (in thousands)			MMcf			per Mcf			Sales (in thousands)		MMcf		per Mcf
Jan-Mar	$	277			87		$	3.21		$	838		115	$	7.32
Apr-Jun		216			98			2.19			908		101		8.95
Jul-Sept		272			101			2.69			746		102		7.31
Oct-Dec		364			91			3.99			375		104		3.61
Total	$	1,129			377		$	2.99		$	2,867		422	$	6.79
Change (year over year)		-61	%		-11	%		-56	%

	2009									2008
Oil	Sales (in thousands)			MBbl			per Bbl			Sales (in thousands)		MBbl		per Bbl
Jan-Mar	$	135		$	5		$	35.48		$	410		4	$	82.11
Apr-Jun		239			4			53.57			434		4		117.70
Jul-Sept		230			4			61.24			425		4		104.19
Oct-Dec		246			3			70.30			167		4		45.83
Total	$	850			16		$	54.78		$	1,436		16	$	87.54
Change (year over year)		-41	%		-5	%		-37	%

Commodity price declines were the primary contributor to the $2.3 million decrease in natural gas and oil sales in 2009 compared to the prior year. The 54% decrease in total sales in 2009 as compared to 2008 was due to a significantly lower average sales price per Mcfe, of 49%, combined with lower production volumes, on a Mcfe or energy equivalency basis, of 10%. The decrease in natural gas revenues of 61% contrasts to the more moderate reduction in oil revenues of 41% which reflects the less significant reduction in average oil sales prices per Bbl, of 37%, as compared to the reduction in natural gas sales prices per Mcf, of 56%, during the period.

On a quarterly basis, total sales for the first, second and third quarters of 2009 as compared to the same periods in 2008, decreased by $0.8 million, $0.9 million and $0.7 million, respectively, due primarily to commodity price declines that were a result of the 2009 economic recession’s downward pressure on demand for natural gas and oil commodities and resulting prices compared to the robust energy commodity price environment before the late-2008 global financial crisis and significant decline in commodity prices. Fourth quarter 2009 total sales increased by $0.1 million from the prior-year comparable period due to the effect of stronger 2009 late-fall natural gas pricing than that of the 2008 global financial crisis period. Although normal quarter-to-prior year quarter production declines are expected, slightly higher second and third quarter 2009 natural gas production volumes were benefitted by four Grand Valley Field’s well’s performance improvement, which offset expected normal production decreases in the Partnership’s remaining wells, compared to well production during prior year quarters.

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Index

Natural Gas and Oil Pricing

Financial results depend upon many factors, particularly the price of natural gas and oil and on PDC’s ability to market the Partnership’s production effectively. Natural gas and oil prices are among the most volatile of all commodity prices. This price volatility has a material impact on the Partnership’s financial results. Natural gas and oil prices also 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 has resulted in a local market oversupply situation from time to time.

The CIG Index, and other indices for natural gas 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 the last year and is lower than 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, cost 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 and subject to the previously noted, “negative differential.” 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.

Commodity Price Risk Management, Net

Natural Gas and Oil Sales Derivative Instruments. The Managing General Partner on behalf of the Partnership in accordance with the D&O Agreement, is authorized to utilize various derivative instruments to manage volatility in natural gas and oil 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 oil production. Under the Partnership’s collar arrangements, should the applicable index rise above the ceiling price, the Managing General Partner pays the difference between the index and the ceiling price to the counterparty; however, should the index drop below the floor price, the counterparty pays the difference between the floor price and the index price to the Managing General Partner. Under the Partnership’s commodity swap arrangements, should the applicable index rise above the swap price, the Managing General Partner pays the difference between the index price and the swap price to the counterparty; however, should the index drop below the swap price, the counterparty pays the difference between the swap price and the index price to the Managing General Partner. Under the Partnership’s basis protection swaps, should the differential widen beyond the swap price, then the counterparty pays the difference between the index price and the swap price to the Managing General Partner; however, should the differential narrow below the swap price, the Managing General Partner pays the difference between the swap price and the index price to the counterparty. See Item 1, Business−Operations – Commodity Price Risk Management for a detailed description of payments under these arrangements. 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, 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.

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~~Index~~Table of Contents

~~The~~Recent following table presents the Partnership’s realized and unrealized derivative gains and losses included in commodity price risk management (loss) gain, net for each of the quarterly and annual periods identified.Developments

	Three months ended																Year ended
	March 31, 2009				June 30, 2009				September 30, 2009				December 31, 2009				December 31, 2009
Commodity price risk management, net
Realized gains
Oil		$	122,049			$	80,415			$	58,470			$	37,747			$	298,681
Natural Gas			384,149				255,859				231,059				260,009				1,131,076
Total realized gain, net			506,198				336,274				289,529				297,756				1,429,757
Unrealized gains (losses)
Reclassification of realized gains included in prior periods unrealized (1)			(419,614	)			(365,002	)			(291,617	)			(281,661	)			(1,221,634	)
Unrealized (loss) gain for the period (1)			(116,628	)			(454,925	)			(343,096	)			137,407				(913,502	)
Total unrealized loss, net			(536,242	)			(819,927	)			(634,713	)			(144,254	)			(2,135,136	)
Commodity price risk management (loss) gain, net		$	(30,044	)		$	(483,653	)		$	(345,184	)		$	153,502			$	(705,379	)

PDC Sponsored Drilling Program Acquisition Plan

	Three months ended																Year ended
	March 31, 2008				June 30, 2008				September 30, 2008				December 31, 2008				December 31, 2008
Commodity price risk management, net
Realized gains (losses)
Oil		$	(23,779	)		$	(68,048	)		$	(48,184	)		$	88,984			$	(51,027	)
Natural Gas			(23,210	)			(182,574	)			64,112				323,853				182,181
Total realized (loss) gain, net			(46,989	)			(250,622	)			15,928				412,837				131,154
Unrealized gains (losses)
Reclassification of realized (gains) losses included in prior periods unrealized (1)			(58,362	)			115,894				253,194				(249,736	)			91,458
Unrealized (loss) gain for the period (1)			(281,189	)			(1,070,165	)			1,735,676				1,218,019				1,571,873
Total unrealized (loss) gain, net			(339,551	)			(954,271	)			1,988,870				968,283				1,663,331
Commodity price risk management (loss) gain, net		$	(386,540	)		$	(1,204,893	)		$	2,004,798			$	1,381,120			$	1,794,485

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.

~~(1)~~In ~~Quarterly~~December ~~amounts~~2010, ~~presented~~PDC onacquired ~~the~~four ~~line~~affiliated ~~captioned~~partnerships: ~~“Unrealized~~PDC ~~(loss)~~2004-A ~~gain~~Limited ~~for the period~~Partnership,” ~~may~~PDC be2004-B ~~reclassified~~Limited ~~in subsequent quarterly periods~~Partnership, toPDC ~~amounts~~2004-C ~~presented~~Limited onPartnership ~~the~~and ~~line~~PDC ~~captioned~~2004-D ~~“Reclassification~~Limited ofPartnership. ~~realized~~PDC ~~(gains)~~purchased ~~losses~~these ~~included~~partnerships infor ~~prior periods unrealized.” For~~ the ~~years~~aggregate ~~2009~~amount ~~and~~of ~~2008, quarterly amounts reclassified in subsequent quarters were~~ $~~136,260~~34.8 ~~and $30,468, respectively~~million.

The ~~$1.4~~feasibility ~~million~~and ~~realized~~timing ~~gain recognized in 2009 is a result~~ of ~~lower~~any ~~natural~~future ~~gas~~purchase ~~and~~offer ~~oil~~by ~~commodity~~PDC ~~prices at settlement compared~~ to ~~the~~any ~~respective~~additional ~~strike~~partnership, ~~price.~~including ~~The~~this Partnership, ~~recognized~~depends ~~realized~~on ~~gains~~that ofpartnership’s ~~$0.5~~suitability ~~million~~in ~~and~~meeting ~~$0.3~~a ~~million,~~set ~~respectively,~~of ~~during~~criteria ~~the~~that ~~2009~~includes, ~~first~~but ~~quarter~~is ~~and~~not ~~each~~limited ~~remaining 2009 quarter due~~ to, the ~~gradual~~following: ~~increase~~age inand ~~the CIG~~productive-~~index~~life ~~natural~~stage ~~gas~~characteristics ~~prices (per MMbtu) and oil prices on NYMEX (per barrel) that occurred within each quarter~~ of the ~~year. The year 2009~~partnership’s ~~relatively~~well ~~stable~~inventory; ~~commodity~~favorability ~~pricing~~of ~~was~~economics infor ~~stark~~Wattenberg ~~contrast~~Field towell ~~the~~refracturing; ~~commodity~~and ~~market~~SEC ~~price~~reporting ~~volatility~~compliance ~~experienced~~status ~~during~~and ~~2008.~~timing ~~Rocky~~associated ~~Mountain~~with ~~Region~~gaining ~~natural~~all ~~gas~~necessary ~~and~~regulatory ~~oil~~approvals ~~prices~~required ~~increased~~for ~~during~~a ~~the~~merger ~~first~~and ~~six~~repurchase ~~months~~offer. There ofis ~~2008,~~no ~~resulting~~assurance inthat ~~the~~any ~~Partnership’s~~merger ~~$0.3~~and ~~million~~acquisition ~~June~~will 30occur, ~~2008~~as ~~realized~~a ~~loss~~result onof ~~its~~PDC’s ~~derivative~~proposed ~~positions.~~repurchase ~~This~~offers ~~loss~~to ~~was~~the ~~offset~~2005 ~~when~~partnerships, ~~commodity~~or ~~prices~~any ~~declined~~potential ~~sharply~~proposed ~~during~~repurchase ~~the~~offer ~~last~~to ~~five~~any ~~months~~other of ~~2008, providing the Partnership~~PDC’s ~~approximately~~various ~~$0.4~~public ~~million~~limited ~~realized gain on its derivative instruments during the December 31~~partnerships, ~~2008~~including ~~quarter~~this ~~and $0.1 million overall gain~~Partnership, ~~for~~should ~~the~~they ~~year ended 2008~~occur.

During 2009, the Partnership recorded current period unrealized derivative losses for the year of approximately $0.9 million. This annual unrealized derivative loss was primarily due to the $0.5 million and $0.3 million, respectively, second and third quarter decreases in fair value of the Partnership’s commodity derivatives, resulting from rising forward strip natural gas and oil commodity prices, in relation to the Partnership’s derivative contract prices combined with the decrease in fair value of the Partnership’s CIG basis protection swaps, resulting from the narrowing of the forward basis differential between NYMEX and CIG indices, in relation to the Partnership’s contract price.

During 2008, the Partnership recorded current period unrealized derivative gains of $1.6 million, primarily related to the Partnership’s natural gas and oil positions which increased in value when the forward prices for natural gas and oil declined substantially in late 2008, relative to the Partnership’s derivative instrument contract prices. The Partnership recognized current period unrealized derivative losses of $0.3 million and $1.0 million, respectively, during the first two quarters of 2008 and unrealized derivative gains of $1.7 million and $1.2 million, respectively, during the remaining two 2008 quarters, as a result of changes in the fair value of the Partnership’s natural gas and oil derivative instruments. As noted earlier, rising Rocky Mountain Region forward strip commodity pricing early in 2008 prior to the global financial crisis, resulted in the Partnership’s quarterly unrealized losses while the steep commodity pricing declines during August through December 2008, resulted in the Partnership’s third and fourth quarter unrealized gains.

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~~Index~~Table of Contents

~~Commodity~~Additional ~~price~~Codell ~~risk~~Formation ~~management,~~Development ~~net~~Plan. The ~~includes~~Managing ~~realized~~General ~~gains~~Partner ~~and~~has ~~losses~~prepared ~~and~~a ~~unrealized~~plan ~~changes~~for in the ~~fair~~Partnership’s ~~value~~Wattenberg ofField ~~derivative~~wells ~~instruments~~which ~~related~~may toprovide ~~the~~for ~~Partnership’s~~additional reserve development and natural gas, NGLs and crude oil production (the “Additional Codell Formation Development Plan”). The ~~See~~Additional ~~Note~~Codell 4,Formation ~~Fair~~Development ~~Value~~Plan consists of ~~Financial~~the ~~Instruments,~~Partnership’s refracturing of wells currently producing in the Codell formation and ~~Note~~the 5recompletion of wells, ~~Derivative~~currently ~~Financial~~producing ~~Instruments~~in the deeper J-Sand formation, toin the ~~accompanying~~shallower ~~financial~~Codell ~~statements~~formation ~~for~~production ~~additional~~zone. Under ~~details~~the ofAdditional Codell Formation Development Plan, the Partnership’s ~~derivative~~plans ~~financial~~to ~~instruments~~initiate additional development activities during 2011. Refracturing, or “refracing,” activities consist of a second hydraulic fracturing treatment in a current production zone, while recompletion activities consist of an initial hydraulic fracturing treatment in a new production zone, all within an existing well bore.

Additional Codell formation development of Wattenberg Field wells, which may provide for additional reserve development and production, generally occurs five to ten years after initial well drilling so that well resources are optimally utilized. This additional Codell formation development would be expected to occur based on a favorable general economic environment and commodity price structure. The ~~following~~Managing ~~table~~General ~~presents~~Partner has the authority to determine whether to recomplete or refracture the individual wells and to determine the timing of any additional Codell formation development activity. The timing of the additional development can be affected by the desire to optimize the economic return by recompleting or refracturing of the wells when commodity prices are at levels to obtain the highest rate of return to the Partnership’. On average, the production resulting from PDC's ~~derivative~~Codell ~~positions~~recompletions inor ~~effect~~refracturings ashave been at modeled economics; however, all recompletions or refracturings have not been economically successful and similar future recompletion or refracturing activities may not be economically successful. If the additional Codell formation development work is performed, PDC will charge the Partnership for the direct costs of ~~June~~recompletion 30or refracturing, ~~2010~~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.

	Collars						Fixed-Price Swaps				CIG Basis Protection Swaps
									Weighted				Weighted
	Quantity		Weighted Average				Quantity		Average		Quantity		Average
Commodity/	(Gas-		Contract Price				(Gas-Mmbtu		Contract		(Gas-		Contract			Fair Value at
Index	Mmbtu)		Floors		Ceilings		Oil-Bbls)		Price		Mmbtu)		Price			June 30, 2010(1)
Natural Gas
CIG
10/01 - 12/31/2010		21,228	$	4.75	$	9.45		-	$	-		-	$	-		$	12,956
01/01 - 03/31/2011		31,842		4.75		9.45		-		-		-		-			15,868
NYMEX
07/01 - 09/30/2010		-		-		-		64,815		5.56		71,323		(1.88	)		(24,317	)
10/01 - 12/31/2010		6,523		5.75		8.30		40,041		6.15		48,862		(1.88	)		(2,492	)
01/01 - 03/31/2011		8,868		5.75		8.30		25,208		6.83		34,076		(1.88	)		(3,064	)
04/01 - 06/30/2011		-		-		-		65,961		6.78		65,961		(1.88	)		23,492
07/01 - 12/31/2011		-		-		-		129,139		6.76		129,139		(1.88	)		2,100
2012-2013		14,905		6.00		8.27		452,811		7.05		467,715		(1.88	)		(18,612	)
Total Natural Gas		83,366						777,975				817,076					5,931
Oil
NYMEX
07/01 - 09/30/2010		-		-		-		2,362		92.96		-		-			39,062
10/01 - 12/31/2010		-		-		-		2,362		92.96		-		-			35,909
01/01 - 03/31/2011		-		-		-		1,248		70.75		-		-			(9,164	)
04/01 - 06/30/2011		-		-		-		1,281		70.75		-		-			(10,435	)
07/01 - 12/31/2011		-		-		-		2,630		70.75		-		-			(23,010	)
Total Oil		-						9,883				-					32,362
Total Natural Gas and Oil																$	38,293

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 additional Codell formation development 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 or recompleted, the Partnership will experience a reduction in proved reserves currently assigned to these wells. Both the number and timing of the additional Codell formation development activities will be based on the availability of cash withheld from Partnership distributions. The Managing General Partner believes that, based on projected refracturing and recompletion costs and projected cash withholding, all scheduled Partnership additional Codell formation development activity will be completed within a five year period. This Partnership has not begun to withhold funds for this additional Codell formation development as this Partnership has outstanding payables to the Managing General Partner.

~~(1)~~Current estimated costs for these well refracturings and recompletions are between $175,000 and $240,000 per activity. As of ~~June~~December 3031, 2010, ~~approximately~~this ~~12%~~Partnership ofhas ~~the~~scheduled ~~fair~~to ~~value~~complete of29 additional Codell formation development opportunities. Total withholding for these activities from the Partnership’s ~~derivative~~distributable ~~assets~~cash flows is estimated to be between $5.1 million and ~~all~~$7.0 ofmillion. The Managing General Partner will continually evaluate the ~~Partnership’s~~timing ~~derivative~~of ~~liabilities~~commencing ~~were~~these ~~measured~~additional ~~using~~Codell ~~significant~~formation ~~unobservable~~development ~~inputs~~activities ~~(Level~~based 3)on engineering data and a favorable commodity price environment in order to maximize the financial benefit of the additional well development. As ~~See~~of ~~Note~~December 431, ~~Fair~~2010 ~~Value~~and ~~Measurements~~through February 28, to2011, ~~the~~no ~~accompanying~~funds ~~financial~~have ~~statements included~~been inwithheld from the Partnership distributions for this ~~report~~recompletion and refracturing.

Implementation of the Additional Codell Formation Development 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 Additional Codell Formation Development 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 Additional Codell Formation Development Plan.

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~~Index~~Table of Contents

~~Natural~~2010 ~~Gas~~ and ~~Oil~~2009 ~~Production~~Partnership ~~Costs~~Overview

Natural gas, NGLs and crude oil ~~production~~sales ~~costs~~increased ~~include~~11% ~~production~~or ~~taxes~~$0.2 ~~and~~million ~~transportation~~for ~~costs~~the ~~which~~2010 ~~vary~~annual ~~with~~period ~~revenues~~compared ~~and~~to ~~production~~2009, ~~well~~even ~~operating~~though ~~costs~~production ~~charged~~volumes ondecreased a11% ~~per~~period-to-period. This ~~well~~revenue ~~basis~~increase ~~and~~was ~~other~~supported ~~direct~~primarily ~~costs~~by ~~incurred~~the inimproved ~~the~~commodity ~~production~~price ~~process~~environment. The Asaverage ~~production~~sales ~~declines~~price per Mcfe, ~~fixed~~excluding ~~costs~~the ~~increase~~impact asof arealized ~~percentage~~derivative ofgains, ~~total~~was ~~costs~~$5.26 ~~resulting~~during in2010 ~~production~~compared ~~costs~~to ~~per~~$4.21 ~~unit~~for ~~increases~~2009. Comparatively, ~~Typically~~the total per Mcfe price realized, asconsisting ~~production~~of isthe ~~expected~~average tosales ~~continue~~price toand ~~decline~~realized derivative gains, ~~production~~decreased ~~costs~~to ~~per~~$6.27 ~~unit~~during ~~can~~2010 befrom ~~expected~~$7.25 during 2009. This decrease was primarily due to ~~increase~~realized inderivative ~~the~~gains ~~future~~from ~~until~~natural ~~such~~gas ~~time~~and ascrude ~~the~~oil ~~Partnership~~sales ~~successfully~~contributing ~~recompletes~~only $1.01 per Mcfe or $0.4 million to the ~~Wattenberg~~2010 ~~Field~~total ~~wells~~revenues as compared to $3.04 ~~The~~per ~~following~~Mcfe ~~table~~or ~~presents~~$1.4 ~~the~~million to 2009 total revenues. The Partnership’s 2010 revenues were favorably impacted by unrealized derivative gains on natural gas and crude oil ~~production~~sales ~~costs~~of ~~recorded~~$0.8 ~~during~~million ~~each~~in of2010 ~~the~~as ~~three~~compared ~~month~~to ~~periods~~unrealized ~~identified:~~losses of $2.1 million in 2009.

	2009						2008
	Prod Costs		Mcfe		per Mcfe		Prod Costs		Mcfe		per Mcfe
Jan-Mar	$	285,334		109,059	$	2.62	$	307,234		144,481	$	2.13
Apr-Jun		211,257		125,284		1.69		364,414		123,578		2.95
Jul-Sep		230,087		123,885		1.86		415,089		126,552		3.28
Oct-Dec		196,858		112,314		1.75		290,438		125,937		2.31
Total	$	923,536		470,542	$	1.96	$	1,377,175		520,548	$	2.65

The Partnership’s combined natural gas and crude oil production expenses and direct costs−administrative and general, increased by $1.1 million during 2010. Higher production expenditures were primarily due to environmental remediation activities during 2010 while higher administrative and general expenses were due to higher fees for professional services.

~~Generally,~~The ~~natural~~Partnership ~~gas~~recorded ~~and~~an ~~oil~~impairment ~~production~~loss ~~costs~~of ~~vary with changes in total natural gas and oil sales and production volumes~~$3.2 ~~Production~~million ~~taxes~~for ~~are estimates by~~ the ~~Managing~~year ~~General~~ended ~~Partner~~December ~~based~~31, ~~on tax rates determined using published information~~2010. The ~~These~~impairment ~~estimates~~loss ~~are~~resulted ~~subject~~from ~~to revision based on actual amounts determined during future filings by~~ the ~~Managing~~downward ~~General~~revision ~~Partner~~to ~~with~~ the ~~taxing~~future ~~authorities.~~net ~~Production~~cash ~~taxes~~flows ~~vary~~of ~~directly with total natural gas and oil sales. Transportation costs vary directly with~~ production ~~volumes.~~activities ~~Fixed~~in ~~monthly~~the ~~well~~Grand ~~operating~~Valley ~~costs~~Field ~~increase~~in ~~on a per unit basis as production decreases per the historical decline curve~~Colorado. See InNote ~~addition~~10, ~~general~~Impairment ~~oil~~of ~~field~~Capitalized ~~services~~Costs ~~and~~to ~~all~~the ~~other~~accompanying ~~costs~~financial ~~vary~~statements ~~and~~for ~~can~~additional ~~fluctuate~~disclosure ~~based~~related onto ~~services~~the ~~required.~~Partnership’s ~~These~~proved ~~costs~~property ~~include water hauling and disposal, equipment repairs and maintenance, snow removal and service rig workovers~~impairment.

~~Natural~~Reporting ~~gas~~on ~~and~~NGLs oil production costs during 2009 were lower by $0.5 million, or 33%, than those of the preceding year primarily due to lower commodity valuations that reduced production taxes and lower lease operating expenses due to lower third-party field services costs. Lowering third party service rates are attributable to declining oil field services demand in this low-commodity price environment, as well as the Managing General Partner’s cost reduction initiatives. Natural gas and oil production costs per Mcfe were $1.96 during the year 2009 compared to $2.65 for the year 2008.2010

OnAs athe ~~quarterly~~Partnership ~~basis~~embarks on the Additional Codell Formation Development Plan, ~~natural~~the ~~gas~~Managing ~~and~~General ~~oil~~Partner ~~production~~believes ~~costs~~that ~~remained~~the ~~substantially~~NGLs ~~unchanged~~will atbe $0an increased percentage of the Partnership’s total revenues and production volumes in future years.3 Additionally, ~~million~~as a result of a computer system upgrade during the ~~first~~second ~~quarter~~half inof 2009, ~~compared~~the Managing General Partner was able to accumulate the ~~respective~~Partnership’s ~~prior~~NGLs ~~year~~sales ~~quarter~~revenues and production volumes for 2010. ~~For~~ Prior to the ~~second~~system ~~through~~upgrade, the ~~fourth~~Partnership’s ~~quarters~~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 ~~oil~~compared ~~production~~it ~~costs~~to ~~decreased~~the by2009 ~~approximately~~natural $0gas results.2 Reporting ~~million~~the Partnership’s information in this fashion, ~~$0.2~~ ~~million~~gives comparability to readers when discussing the Partnership’s year to year results and $0provides more detailed information which may be beneficial for understanding the Partnership’s current business.1 Starting ~~million from~~in the ~~comparable~~first ~~2008~~quarter ~~quarters~~of 2011, ~~respectively~~all of the Partnership’s revenues and production volumes of natural gas, ~~primarily~~NGLs asand crude oil will be presented in a ~~result~~fashion comparable to the ~~Managing~~2010 ~~General~~information ~~Partner’s~~contained ~~cost~~in ~~reduction~~this ~~initiatives~~report.

Natural gas and oil production cost per Mcfe increases during the second and third quarters of 2008 primarily reflect the combined effect of the Partnership’s higher production tax expenditures due to higher commodity valuations and higher lease operating costs because of Grand Valley Field access road maintenance and remediation at four Partnership wells located at one Grand Valley well pad. The fourth quarter 2008 production cost per Mcfe decrease is the result of the combined effect of the lower production tax expenditures due to significantly lower commodity valuations during the late-2008 global credit crisis period and lower lease operating costs.

Natural gas and oil production cost per Mcfe variations during 2009 are primarily the result of changes in lease operating expenditures. First quarter 2009 lease operating costs reflect well and surface equipment installation at the Partnership’s four Grand Valley wells noted above, combined with surface equipment installation at three Wattenberg Field wells. Reductions in natural gas and oil production costs per Mcfe during the second and third quarters of 2009 primarily reflect lower lease operating expenses due to lower third-party field services costs, whose lowering rates are attributable to declining oil field services demand in this low-commodity price environment, and the Managing General Partner’s cost reduction initiatives. During fourth quarter 2009, the Partnership recorded a downward revision of 2009 production taxes that was applicable to prior quarters’ production.

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~~Index~~Table of Contents

~~Depreciation,~~Results ~~Depletion~~of ~~and Amortization~~Operations

~~The~~Summary ~~following~~Operating ~~table presents the Partnership’s depreciation, depletion, and amortization (“DD&A”) expense recorded for each of the three month periods identified:~~Results

	2009						2008
	DD&A		Mcfe		per Mcfe		DD&A		Mcfe		per Mcfe
Jan-Mar	$	500,354		109,059	$	4.59	$	399,586		144,481	$	2.77
Apr-Jun		544,824		125,284		4.35		336,606		123,578		2.72
Jul-Sep		546,305		123,885		4.41		349,954		126,552		2.77
Oct-Dec		471,508		112,314		4.20		552,955		125,937		4.39
Total	$	2,062,991		470,542	$	4.38	$	1,639,101		520,548	$	3.15

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.

Depreciation, depletion and amortization (DD&A) expense results solely from the depreciation, depletion and amortization of well equipment and lease costs. The Partnership’s calculation of DD&A expense is primarily based upon year-end proved developed producing natural gas and oil reserve estimates and associated production volumes. For 2008, the Partnership’s natural gas and oil economically producible reserve quantities were 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 natural gas and oil 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 each month of 2009. Typically as valuation prices increase, the estimated volumes of natural gas and oil reserves may increase, resulting in a decrease in the rate of DD&A for each Mcfe produced. If valuation prices decrease the estimated volumes of natural gas and oil reserves may also decrease, resulting in an increase in the DD&A rate for each Mcfe produced.

	Year Ended December 31,
	2010		2009		Change
Number of producing wells (end of period)		43		43		-

Production(1)
Natural gas (Mcf)		318,777		377,410		-16	%
NGLs (Bbl)		4,080		-		*
Subtotal natural gas and NGLs (Mcfe)(2)		343,257		377,410		-9	%
Crude oil (Bbl)		12,324		15,522		-21	%
Natural gas equivalents (Mcfe)(2)		417,201		470,542		-11	%
Mcfe per day		1,143		1,289		-11	%

Natural Gas, NGLs and Crude Oil Sales
Natural gas	$	1,130,232	$	1,129,413		0	%
NGLs		172,199		-		*
Subtotal natural gas and NGLs		1,302,431		1,129,413		15	%
Crude oil		890,904		850,265		5	%
Total natural gas, NGLs and crude oil sales	$	2,193,335	$	1,979,678		11	%

Realized Gain on Derivatives, net
Natural gas	$	296,594	$	1,131,076		-74	%
Crude oil		125,626		298,681		-58	%
Total realized gain on derivatives, net	$	422,220	$	1,429,757		-70	%

Average Selling Price (excluding realized gain on derivatives)
Natural gas (per Mcf)	$	3.55	$	2.99		19	%
NGLs (per Bbl)		42.21		-		*
Natural gas and NGLs (per Mcfe)		3.79		2.99		27	%
Crude oil (per Bbl)		72.29		54.78		32	%
Natural gas equivalents (per Mcfe)		5.26		4.21		25	%

Average Selling Price (including realized gain on derivatives)
Natural gas (per Mcf)	$	4.48	$	5.99		-25	%
NGLs (per Bbl)		42.21		-		*
Natural gas and NGLs (per Mcfe)		4.66		5.99		-22	%
Crude oil (per Bbl)		82.48		74.02		11	%
Natural gas equivalents (per Mcfe)		6.27		7.25		-14	%

Average cost per Mcfe
Natural gas, NGLs and crude oil production cost(3)	$	3.41	$	1.96		74	%
Depreciation, depletion and amortization		4.03		4.38		-8	%

Operating costs and expenses:
Direct costs - general and administrative	$	666,746	$	82,202		*
Depreciation, depletion and amortization	$	1,682,408	$	2,062,991		-18	%
Loss on impairment of natural gas and crude oil properties	$	3,242,907	$	-		*

Cash distributions	$	1,246,773	$	3,631,694		-66	%

~~The~~*Percentage ~~DD&A~~change ~~expense~~not ~~rate per Mcfe increased to $4.38 for the year ended December 31~~meaningful, ~~2009,~~equal ~~compared~~ to ~~$3.15~~or ~~during~~greater ~~the~~than ~~same~~250% ~~period~~or innot ~~2008~~calculable. Amounts ~~The~~may ~~variance~~not incalculate ~~the~~due ~~annual per Mcfe rates for the 2009 period compared~~ to the 2008 period is the result of the changing production mix between the Partnership’s Wattenberg and Grand Valley Fields, which have significantly different DD&A rates in addition to the effects of downward revisions in the Partnership’s proved developed producing natural gas and oil reserves at December 31, 2008 compared to December 31, 2007rounding. The Partnership’s downward year-end 2008 proved developed producing reserve revision was the primary contributor to the increased DD&A expense of $0.5 million during the first three quarters of 2009. Fourth quarter 2009 DD&A expense declined approximately $0.1 million compared to fourth quarter 2008, primarily based on a Wattenberg Field upward natural gas and oil proved developed producing reserves revision from the Partnership's December 31, 2009 annual reserve report. Overall, DD&A expense increased $0.4 million during 2009 compared to the prior year. The Partnership’s 2009 annual production volumes, on an Mcfe or energy-equivalency basis, decreased by 10% over 2008 production volumes.

The higher fourth quarter 2008 DD&A expense rate per Mcfe compared to the year’s earlier quarter-periods is due to the utilization of the year-end 2008 report’s lower proved developed producing natural gas and oil reserve volumes compared to year-end 2007 reported reserves that was used in determining DD&A expense in earlier 2008 quarters. The lower fourth quarter 2009 DD&A expense rate per Mcfe compared to 2009’s earlier quarter-periods is due to the fourth quarter’s use of the year-end 2009 report’s lower Wattenberg Field proved developed producing natural gas and oil reserve volumes, compared to year-end 2008 reserves, as noted above. See Supplemental Natural Gas and Oil Information – Unaudited, Net Proved Natural Gas and Oil Reserves that accompanies the financial statements included in this Annual Report, for additional information regarding the Partnership’s reserves reported as of December 31, 2009 and 2008.__________________

(1)

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

(2)

A ratio of energy content of natural gas, 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 natural gas, NGLs and crude oil operating expenses which include production taxes.

- 28 -

~~Index~~Table of Contents

~~Liquidity~~Natural Gas, NGLs and ~~Capital~~Crude ~~Resources~~Oil Sales

~~The~~Changes ~~Partnership’s primary sources of cash~~ in ~~2009~~Natural ~~were provided by operating activities which include the sale of natural gas and oil production~~Gas, ~~the~~NGLs ~~net realized gains from the Partnership’s derivative positions~~ and ~~the~~Crude ~~decrease~~Oil inProduction ~~“Due from Managing General Partner – Other, Net~~Volumes.” For ~~These sources of cash were primarily used to fund~~ the ~~Partnership’s~~2010 ~~operating~~annual ~~cost,~~period ~~general~~compared ~~and administrative activities and provide monthly distributions~~ to the ~~Investor~~2009 ~~Partners~~annual ~~and PDC~~period, ~~the~~natural ~~Managing General Partner. Fluctuations in the Partnership’s operating cash flow are substantially driven by changes in commodity prices~~gas, inNGLs ~~production volumes~~ and incrude realized gains and losses from commodity positions. Commodity prices have historically been volatile and the Partnership attempts to manage this volatility through derivatives. Therefore, the primary source of the Partnership’s cash flow from operations becomes the net activity between the Partnership’s natural gas and oil ~~sales and realized derivative gains and losses. However~~production, ~~the~~on ~~Partnership~~an ~~does~~energy ~~not engage in speculative positions~~equivalency-basis, ~~nor~~decreased ~~does~~11% ~~the~~due ~~Partnership~~to ~~hold~~normal ~~derivative~~production ~~instruments~~declines for ~~100%~~this ofstage in the ~~Partnership~~wells’s ~~expected future~~ production ~~from~~life ~~producing wells and therefore may still experience significant fluctuations in cash flows from operations. As of June 30~~cycle, ~~2010,~~ the ~~Partnership~~Wattenberg ~~had~~Field ~~natural~~production ~~gas~~reduction ~~and~~that ~~oil~~resulted ~~derivative~~from ~~positions~~a inwell ~~place~~equipment ~~covering~~issue ~~79% of expected natural gas production~~ and ~~71%~~lower ofGrand ~~expected~~Valley ~~oil~~Field ~~production~~well ~~for~~performance ~~the remainder of 2010,~~ at ansome ~~average~~wells ~~price~~due ofto ~~$3.91~~intermittent ~~per~~field ~~Mcf~~operational ~~and $92~~constraints.96 per Bbl, respectively. 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.

~~The~~Changes ~~Partnership’s~~in ~~future~~Natural ~~operations~~Gas ~~are expected to be conducted with available funds~~ and ~~revenues~~NGLs ~~generated~~Sales. During ~~from~~2010, ~~natural~~the ~~gas~~Partnership ~~and~~began ~~oil~~separate ~~production~~reporting ~~activities~~of ~~and~~NGL ~~commodity~~sales, ~~gains~~which ~~(losses).~~were ~~Natural~~previously ~~gas~~classified and ~~oil~~reported ~~production~~as ~~from the Partnership’s existing properties are generally expected to continue~~ a ~~gradual~~component ~~decline~~of innatural ~~the~~gas ~~rate~~sales ofrevenues. Combined ~~production~~2010 ~~over~~natural ~~the~~gas ~~remaining~~and ~~life~~NGL ofsales ~~the~~were ~~wells~~$0.2 ~~Therefore~~million, ~~the~~or ~~Partnership~~15% ~~anticipates~~higher athan ~~lower~~comparably ~~annual~~reported ~~level~~2009 of natural gas ~~and~~sales ~~oil~~revenues. Combined production ~~and,~~from innatural ~~the~~gas ~~absence~~and ofNGLs ~~significant~~were ~~price increases or additional reserve development~~343,257 ~~lower~~Mcfe ~~revenues.~~in ~~The~~2010 ~~Partnership~~compared ~~also expects cash flows from operations~~ to ~~decline~~377,410 ifMcfe ~~commodity~~in ~~prices~~2009. This ~~remain~~34,153 atMcfe ~~current levels~~ or ~~decrease~~9% reduction in ~~the future. Under these circumstances decreased~~ production ~~would~~was ~~have~~more athan ~~material~~offset ~~negative~~by ~~impact on~~ the ~~Partnership’s~~higher ~~operations~~average ~~and~~selling ~~may~~price ~~result~~for inthese ~~reduced~~commodities ~~cash~~of ~~distributions~~$3.79 toper ~~the~~Mcfe ~~Investor Partners~~ in 2010 ~~and~~compared ~~beyond and may substantially reduce or restrict the Partnership’s ability~~ to ~~participate~~$2.99 in ~~additional~~2009. This ~~development activities~~$0.80 ~~Future~~per ~~cash~~Mcfe ~~distributions~~increase ~~may~~represents ~~also~~a be27% ~~reduced~~overall toprice ~~fund~~increase ~~additional~~from ~~Codell formation development activities in~~ the ~~Wattenberg~~prior ~~Field~~year.

~~Working~~Changes ~~Capital~~in Crude Oil Sales. Crude oil sales for the 2010 annual period as compared to the 2009 annual period remained stable at $0.9 million, which was primarily the reflection of a higher average sales price per Bbl of 32% that was offset by the production volume decrease of 21%. The average sales price per Bbl, excluding the impact of realized derivative gains, was $72.29 for the current year annual period compared to $54.78 for the same period a year ago.

Natural Gas, NGLs and Crude Oil Pricing. The ~~following~~Partnership’s ~~table~~results ~~presents~~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 ~~working~~production ~~capital~~effectively. Natural ~~position~~gas, atNGLs and crude oil prices are among the ~~end~~most volatile of all commodity prices. These price variations have a material impact on the ~~three~~Partnership’s ~~month~~financial ~~period~~results. Natural ~~indentified:~~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.

	As of
	March 31, 2009		June 30, 2009		September 30, 2009		December 31, 2009
Working capital	$	3,495,130	$	2,832,432	$	987,735	$	776,530
	As of
	March 31, 2008		June 30, 2008		September 30, 2008		December 31, 2008
Working capital	$	1,976,871	$	1,180,916	$	2,442,494	$	3,241,197

The price at which PDC markets the natural gas produced in the Rocky Mountain Region by the Partnership is based on a variety of prices, which primarily includes natural gas sold at Colorado Interstate Gas, or CIG, prices with a portion sold at Mid-Continent, San Juan Basin, Southern California or other nearby regional prices. The CIG Index, and other indices for production delivered to other Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is primarily New York Mercantile Exchange, or NYMEX, based, because of the lack of interstate transmission capacity which moved Rocky Mountain natural gas production to Northeastern U.S. industrial and heating markets. This negative differential has narrowed in the last few years and is lower than historical variances. The negative differential between NYMEX and CIG averaged $0.47 and $0.92 for 2010 and 2009, respectively.

Working capital at December 31, 2009 was $0.8 million compared to working capital of $3.2 million at December 31, 2008, a decrease of approximately $2.4 million. This decrease was primarily due to the following changes in accounts receivable and payable balances:

● Natural gas and oil receivables decreased by approximately $0.1 million between December 31, 2009 and 2008.

● Realized derivative gains receivables decreased by $0.2 million between December 31, 2009 and December 31, 2008.

● Net short-term unrealized derivative gains receivable decreased by $1.2 million between December 31, 2009 and December 31, 2008.

- 29 -

~~Index~~Table of Contents

●Commodity ~~The~~Price ~~liability~~Risk ~~Due to Managing General Partner-other~~Management, ~~excluding natural gas and oil sales received from third parties and realized derivative gains, increased by $0.9 million between December 31, 2009 and December 31, 2008.~~Net

~~Amounts~~Commodity ~~Due~~price torisk ~~(from) the Managing General Partner-other~~management, ~~described above~~net, ~~were~~includes ~~impacted~~realized bygains ~~non-recurring~~and ~~items~~losses ~~during~~and ~~the~~unrealized ~~period~~changes ~~ended September 2009. There was a net reduction of $1.4 million~~ in ~~amounts due from~~ the ~~Managing~~fair ~~General~~value ~~Partner,~~of asderivative ainstruments ~~$1.6 million receivable for over-withheld production taxes~~ related to ~~Partnership production prior to 2007 was collected. In addition,~~ the Partnership’s ~~settled~~natural ~~the~~gas ~~obligation~~and ~~for~~crude ~~the~~oil ~~Colorado Royalty Settlement of approximately $0~~production.2 See ~~million.~~Note ~~The~~3, ~~net~~Fair ~~cash~~Value ~~impact~~ of ~~these~~Financial ~~transactions~~Instruments, ~~increased~~and ~~distributions~~Note ~~by $1.~~4, ~~million~~Derivative ~~during~~Financial ~~2009.~~Instruments, ~~For~~to ~~more information on~~ the ~~Colorado~~Partnership’s ~~Royalty~~financial ~~Settlement~~statements ~~see~~included ~~Note~~in 9,this ~~Commitments~~report ~~and~~for ~~Contingencies~~additional todetails of the ~~accompanying~~Partnership’s ~~audited~~derivative financial ~~statements~~instruments.

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

	Year Ended December 31,
Commodity price risk management, net	2010			2009
Realized gain
Natural Gas	$	296,594		$	1,131,076
Crude Oil		125,626			298,681
Total realized gain, net		422,220			1,429,757

Unrealized gain (loss)
Reclassification of realized gain included in prior periods unrealized		(34,852	)		(1,221,634	)
Unrealized gain (loss) for the period		881,311			(913,502	)
Total unrealized gain (loss), net		846,459			(2,135,136	)
Commodity price risk management gain (loss), net	$	1,268,679		$	(705,379	)

Realized gains recognized in 2010 and 2009 are a result of lower natural gas and crude oil spot prices at settlement compared to the respective strike price, offset in part by the negative basis differential between NYMEX and CIG being narrower than the strike price of the Partnership’s derivative position. During 2010, the Partnership recorded unrealized gains of $1.0 million on the Partnership’s natural gas and crude oil positions that were partially offset by unrealized losses of $0.1 million on its CIG basis swaps as the forward basis differential between NYMEX and CIG had continued to narrow from the prior year.

During 2009, the Partnership recorded unrealized losses on its CIG basis swaps as the forward basis differential between NYMEX and CIG had continued to narrow from the prior year along with unrealized losses on the Partnership’s crude oil positions, offset by unrealized gains on the Partnership’s natural gas positions.

Natural Gas and Crude Oil Sales Derivative Instruments. The Partnership uses various derivative instruments to manage fluctuations in natural gas and crude oil prices. The Partnership has in place a variety of floors, collars, fixed-price swaps and basis swaps on a portion of the Partnership’s estimated natural gas and crude oil production. Because the Partnership sells its 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 3, Fair Value of Financial Instruments, and Note 4, Derivative Financial Instruments, to the Partnership’s financial statements included in this report on how each derivative type impacts the Partnership’s cash flows and detailed presentation of the Partnership’s derivative positions as of December 31, 2010.

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Table of Contents

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

	Collars						Fixed-Price Swaps				CIG Basis Protection Swaps
Commodity/ Index	Quantity (Gas-Mmbtu(1))		Weighted Average Contract Price				Quantity (Gas-Mmbtu(1) Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-Mmbtu(1))		Weighted Average Contract Price			Fair Value at December 31, 2010(2)
Commodity/ Index	Quantity (Gas-Mmbtu(1))		Floors		Ceilings		Quantity (Gas-Mmbtu(1) Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-Mmbtu(1))		Weighted Average Contract Price			Fair Value at December 31, 2010(2)

Natural Gas
CIG
01/01 - 03/31/2011		31,842	$	4.75	$	9.45		-	$	-		-	$	-		$	24,721

NYMEX
01/01 - 03/31/2011		8,868		5.75		8.30		25,208		6.83		34,076		(1.88	)		23,998
04/01 - 06/30/2011		-		-		-		65,961		6.78		65,961		(1.88	)		63,477
07/01 - 09/30/2011		-		-		-		65,308		6.73		65,308		(1.88	)		51,145
10/01 - 12/31/2011		-		-		-		63,831		6.78		63,831		(1.88	)		32,727
2012		14,905		6.00		8.27		227,626		6.98		242,530		(1.88	)		106,114
2013		-		-		-		225,185		7.12		225,185		(1.88	)		94,395
Total Natural Gas		55,615						673,119				696,891					396,577

Crude Oil
NYMEX
01/01 - 03/31/2011		-		-		-		1,248		70.75		-					(25,927	)
04/01 - 06/30/2011		-		-		-		1,281		70.75		-					(28,394	)
07/01 - 09/30/2011		-		-		-		1,313		70.75		-					(29,685	)
10/01 - 12/31/2011		-		-		-		1,317		70.75		-					(29,815	)
Total Crude Oil		-						5,159				-					(113,821	)

Total Natural Gas and Crude Oil																$	282,756

(1)

A standard unit of measure for natural gas (one MMBtu equals one Mcf).

(2)

As of December 31, 2010, approximately 4% of the fair value of the Partnership’s derivative assets and all of the Partnership’s derivative liabilities were measured using significant unobservable inputs (Level 3).

Natural Gas, NGLs and Crude Oil Production Costs

Natural gas, NGLs and crude oil production costs include production taxes and transportation costs which vary with revenues and production, well operating costs charged on a per well basis and other direct costs incurred in the production process. As production declines, fixed costs increase as a percentage of total costs resulting in production costs per unit increases. Typically, as production is expected to continue to decline, production costs per unit can be expected to increase in the future until such time as the Partnership successfully recompletes the Wattenberg Field wells.

Generally, natural gas, NGLs and crude oil production costs vary with changes in total natural gas, NGLs and crude oil sales and production volumes. Production taxes are estimates by the Managing General Partner based on tax rates determined using published information. These estimates are subject to revision based on actual amounts determined during future filings by the Managing General Partner with the taxing authorities. Production taxes vary directly with total natural gas, NGLs and crude oil sales. Transportation costs vary directly with production volumes. Fixed monthly well operating costs increase on a per unit basis as production decreases per the historical decline curve. In addition, general oil field services and all other costs vary and can fluctuate based on services required but are expected to increase as wells age and require more extensive repair and maintenance. These costs include water hauling and disposal, equipment repairs and maintenance, snow removal and service rig workovers.

Changes in natural gas, NGLs and crude oil production expenses. Production and operating costs were higher by approximately $0.5 million during 2010 compared to 2009, due in part, to the nonrecurring environmental remediation expenses of $0.4 million, which includes a December 31, 2010 accrual of $0.1 million. Additionally 2010 Partnership lease operating expenses were higher as a result of higher Grand Valley fluid disposal and hauling costs, while well operations costs were higher as a result of the increase in the per well operations fee charged by the Managing General Partner, consistent with the terms of the D&O Agreement. These production expense increases were partially offset by volume-associated reductions in production taxes, natural gas transportation and lease operating expenses due to the production volume declines previously noted in the section, Natural Gas, NGLs and Crude Oil Sales. Production and operating costs per Mcfe rose to $3.41 during 2010 compared to $1.96 during 2009 due to the effect of higher per-well related expenditures offset by lower per-volume related natural gas, NGLs and crude oil production costs.

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Direct Costs−General and 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 increased during the 2010 annual period compared to the 2009 annual period, by approximately $0.6 million principally due to increased fees for professional services related to the Partnership’s SEC reporting compliance efforts.

Depreciation, Depletion and Amortization

Natural gas and crude oil properties. Depreciation, depletion and amortization (DD&A) expense related to natural gas and crude oil properties is directly related to proved reserves and production volumes. DD&A expense is primarily based upon year-end proved developed producing reserves. The pricing measurement for reserve estimations is a 12-month average of the first day of the month price for each month in the period. If prices increase, the estimated volumes of proved reserves will increase, resulting in decreases in the rate of DD&A per unit of production. If prices decrease, the estimated volumes of proved reserves will decrease, resulting in increases in the rate of DD&A per unit of production.

Changes in DD&A expense. The DD&A expense rate per Mcfe decreased to $4.03 during 2010 compared to $4.38 during 2009. The DD&A rate decrease was due to the changing production mix between the Partnership’s Wattenberg and Grand Valley Fields, which have significantly different DD&A rates, in addition to the effect of the upward revision in the Partnership’s Wattenberg Field’s proved developed producing natural gas, NGLs and crude oil reserves at December 31, 2009. The decreased DD&A expense rate, combined with the effect of the production decline noted in previous sections, resulted in a decreased DD&A expense of approximately $0.4 million for 2010 compared to 2009.

Loss on Impairment of Natural Gas and Crude Oil Properties

The Partnership assesses its proved natural gas and crude oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the Managing General Partner reasonably estimates the commodities to be sold. The Partnership considers the receipt of the annual reserve report from independent engineers to be a triggering event. Therefore, impairment tests are completed as of December 31 each year. The estimates of future prices may differ from current market prices of natural gas and crude oil. Certain events, including but not limited to, downward revisions in estimates to the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs, could also result in a triggering event and, therefore, a possible impairment of the Partnership’s proved natural gas and crude oil properties. If during the completion of the impairment test, net capitalized costs exceed undiscounted future net cash flows, as occurred for the year ended December 31, 2010, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis, which is predominantly unobservable data or inputs (Level 3), and is measured by the amount by which the net capitalized costs exceed their fair value. The Partnership’s estimated production used in the impairment testing is taken from the annual reserve report (See Supplemental Natural Gas, NGL and Crude Oil Information –Unaudited—Net Proved Reserves). Estimated undiscounted future net cash flows are determined using prices from the forward price curve at the measurement date. Estimated discounted future net cash flows were determined utilizing a risk adjusted discount rate that is based on rates utilized by market participants that are commensurate with the risks inherent in the development of the underlying natural gas and crude oil reserves. A decline in the forward price curves used to estimate future cash flows at December 31, 2010 accompanied by lower reserves reflected in the Partnership’s annual reserve report resulted in an impairment in the fourth quarter of 2010. This downward revision to the future net cash flows resulted primarily from a 1,088 or 36.1% decrease in future estimated MMcfs of natural gas production due to well economics and a reduction in prices from 2009. The Partnership recorded an impairment loss of $3.2 million for the year ended December 31, 2010. The Partnership recognized no impairment of its natural gas and crude oil properties as of December 31, 2009. The 2010 impairment loss resulted from the downward revision to the fair value of discounted future net cash flows of production activities in the Grand Valley Field in Colorado. The Partnership has recognized impairment losses from inception to December 31, 2010 of $11.9 million on its natural gas and crude oil properties since the Partnership began operating in 2003.

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Financial Condition

Capital Resources and Liquidity

The Partnership’s primary sources of cash for both the 2010 and the 2009 annual periods were from funds provided by operating activities which include the sale of natural gas, NGLs and crude oil production and the realized gains from the Partnership’s derivative positions. These sources of cash were primarily used to fund the Partnership’s operating cost, general and administrative activities and provided monthly distributions to the 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. Commodity prices have historically been volatile and the Partnership attempts to manage this volatility through derivatives. Therefore, the primary source of the Partnership’s cash flow from operations becomes the net activity between the Partnership’s natural gas, NGLs and crude oil sales and realized natural gas and crude oil derivative gains and losses. However, the Partnership does not engage in speculative positions, nor does the Partnership hold derivative instruments for 100% of the Partnership’s expected future production from producing wells and therefore may still experience significant fluctuations in cash flows from operations. As of December 31, 2010, the Partnership had natural gas and crude oil derivative positions in place covering 89% of expected natural gas production and 48% of expected oil production for 2011, at an average price of $4.84 per Mcf and $70.75 per Bbl, respectively. The Partnership’s current derivative position average prices have declined from the significantly higher average commodity contract strike price levels in effect during the 2009 comparative period which were the result of contracts entered into during the high 2008 commodity price market; accordingly, the Partnership anticipates realized gains for the next 12 months to remain substantially below gains realized in 2010 and 2009. 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.

The Partnership’s future operations are expected to be conducted with available funds and revenues generated from natural gas, NGLs and crude oil production activities and commodity gains. Natural gas, NGLs and crude oil production from the Partnership’s existing properties are generally expected to continue a gradual decline in the rate of production over the remaining life of the wells. Therefore, the Partnership anticipates a lower annual level of natural gas, NGLs and crude oil production and, in the absence of significant price increases or additional reserve development, lower revenues. The Partnership also expects cash flows from operations to decline if commodity prices remain at current levels or decrease in the future. Under these circumstances decreased production would have a material negative impact on the Partnership’s operations and may result in reduced cash distributions to 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 recompletion and refracturing activities which are more fully described in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments−Additional Codell Formation Development Plan.

Working Capital

The Partnership had working capital at December 31, 2010 of $0.1 million compared to working capital of $0.8 million at December 31, 2009, a decrease of approximately $0.7 million. This decrease was primarily due to the following changes:

Realized derivative gains receivables decreased by $0.1 million between December 31, 2010 and December 31, 2009.

Accounts payable and accrued expenses increased by $0.1 million as of December 31, 2010 compared to December 31, 2009, primarily due to the environmental remediation accrual.

Due to the Managing General Partner-other payable, excluding natural gas, NGLs and crude oil sales received from third parties and realized derivative gains, increased by approximately $0.5 million as of December 31, 2010 compared to December 31, 2009.

Working capital, primarily cash and cash equivalents, is expected to increase during early 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 additional Codell formation development activities. This withholding is expected to begin in the first quarter of 2011. Cash will begin to decrease as the funds are utilized in payment of the completed development activities, currently planned to occur during mid-to-late 2011. Funding for the Additional Codell Formation Development 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 Additional Codell Formation Development Plan funding and by decreasing during periods when payments are made for completed refracturing or recompletion.

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Table of Contents

Cash Flows

Cash Flows From Operating Activities

Net cash provided by operating activities was $1.3 million for 2010 compared to $3.7 million for 2009, a decrease of approximately $2.4 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 $0.1 million, or 5%;

A decrease in commodity price risk management realized gains receipts of approximately $1.0 million, or 64%, accompanied by increases in natural gas, NGLs and crude oil production costs of $0.5 million, or 54% and direct costs-general and administrative of $0.6 million;

A decrease in Due to Managing General Partner-other, net, receipts of approximately $0.4 million, excluding natural gas, NGLs and crude oil sales received from third parties and realized derivative gains.

Cash Flows From Investing Activities

The Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas and crude oil or environmental protection. These amounts totaled approximately $6515,000 and $2365,000 for ~~2009~~2010 and ~~2008~~2009, respectively.

Cash Flows From Financing Activities

The Partnership initiated monthly cash distributions to investors in July 2004 and has distributed $2830.70 million through December 31, ~~2009~~2010. The table below presents cash distributions to the Partnership’s investors. Managing General Partner distributions include amounts distributed to PDC for its Managing General Partner’s 20% ownership share in the Partnership. Investor Partner distributions include amounts distributed to Investor Partners for their 80% ownership share in the Partnership and include amounts distributed to PDC for limited partnership units repurchased.

	Managing		Investor
Year Ended	Managing General Partner Distributions		Investor Partners Distributions		Total Distributions
	General Partner		Partners		Total
2010	$	249,354	$	997,419	$	1,246,773
	Distributions		Distributions*		Distributions
2009	$	726,339	$	2,905,355	$	3,631,694
2009
Jan-Mar	$	101,655	$	406,616	$	508,271
Apr-Jun		143,399		573,598		716,997
Jul-Sep		370,953		1,483,815		1,854,768
Oct-Dec		110,332		441,326		551,658
	$	726,339	$	2,905,355	$	3,631,694
2008
Jan-Mar	$	136,965	$	547,863	$	684,828
Apr-Jun		194,338		777,355		971,693
Jul-Sep		172,675		690,704		863,379
Oct-Dec		152,165		608,663		760,828
	$	656,143	$	2,624,585	$	3,280,728

*The ~~following~~decrease ~~table~~in ~~presents~~total ~~these~~distributions ~~equity~~for ~~cash~~2010 ~~distributions~~as ~~during~~compared to 2009 is primarily due to the ~~three~~significant ~~month~~decrease ~~periods~~in ~~identified,~~cash ~~associated~~flows tofrom ~~limited~~operating ~~partnership~~activities ~~units~~during ~~repurchased~~these byrespective ~~PDC:~~years.

Three months ended	2009		2008
March 31	$	8,545	$	3,987
June 30		12,403		6,147
September 30		35,169		5,561
December 31		10,552		8,814

Additionally, due to the Additional Codell Formation Development Plan the Managing General Partner’s and Investor Partners’ distributions are expected to decrease in 2011. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Recent Developments−Additional Codell Formation Development Plan.

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~~Index~~Table of Contents

Cash Flows From Operating Activities

The following table presents the operating cash flows for the end of the three month periods identified:

	2009
	Quarter ended		Quarter ended		Quarter ended		Quarter ended
	March 31,		June 30,		September 30,		December 31,
Cash flows from operating activities	$	575,845	$	692,424	$	1,873,889	$	555,817
	2008
	Quarter ended		Quarter ended		Quarter ended		Quarter ended
	March 31,		June 30,		September 30,		December 31,
Cash flows from operating activities	$	689,914	$	975,872	$	880,228	$	769,542

Net cash provided by operating activities was $3.7 million for 2009 compared to $3.3 million for 2008, an increase of approximately $0.4 million. The increase in cash provided by operating activities was due primarily to the following:

● A decrease in natural gas and oil sales receipts of $2.5 million, or 54%;

● An increase in commodity price risk management realized gains receipts of $1.8 million and a decrease in natural gas and oil production costs of $0.5 million, or 33%;

● A decrease in oil inventory of $0.1 million; and

● An increase in Due from Managing General Partner-other receipts, excluding natural gas and oil sales receipts and realized derivative gain receipts noted above, of approximately $0.5 million primarily due to the non-recurring third quarter 2009 Managing General Partner’s $1.6 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 $0.2 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. 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:

-Natural 31Gas -and Crude Oil Properties

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

~~Revenue~~Annually, ~~Recognition~~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, 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.

~~Natural~~Proved ~~Gas~~developed ~~Sales.~~reserves ~~Sales of natural gas~~ are ~~recognized~~those ~~when~~ natural gas ~~has been delivered to a custody transfer point~~, ~~persuasive~~NGLs ~~evidence of a sales arrangement exists, the rights~~ and ~~responsibility~~crude ofoil ~~ownership~~quantities ~~pass~~expected to ~~the~~be ~~purchaser~~recovered ~~upon delivery, collection of revenue~~ from ~~the~~currently ~~sale~~producing iszones ~~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~~continuation of ~~the~~present ~~well~~operating methods. Proved ~~Virtually~~undeveloped ~~all of the Managing General Partner’s contracts’ pricing provisions are tied to a market index with certain adjustments based on~~reserves, ~~among~~or ~~other factors~~PUDs, ~~whether~~are athose ~~well~~reserves ~~delivers~~expected to abe ~~gathering~~recovered orfrom ~~transmission~~existing ~~line,~~wells ~~quality~~where ~~of gas and prevailing supply and demand conditions. As~~ a ~~result,~~relatively ~~the~~major ~~Partnership’s~~expenditure ~~revenues~~is ~~from~~required ~~the~~for ~~sale~~additional ofreserve ~~natural gas will decrease if market prices decline and increase if market prices increase~~development. ~~The Partnership believes that the pricing provisions of its natural gas contracts are customary in the industry.~~

The Partnership ~~currently~~assesses ~~uses~~its ~~the~~natural ~~“Net~~gas and crude oil properties for possible impairment by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-~~Back”~~by-field ~~method~~basis using estimated production based upon prices at which management reasonably estimates commodities to be sold. The estimates of ~~accounting~~future ~~for~~prices ~~transportation~~may ~~arrangements~~differ from current market prices of natural gas, ~~sales~~NGLs and crude oil. Any ~~The~~downward ~~Managing~~revisions ~~General~~in ~~Partner~~estimates ~~sells~~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 atand crude oil properties. Although the ~~wellhead~~Partnership’s ~~and~~cash ~~recognizes~~flow ~~revenues~~estimates are based on the ~~wellhead~~relevant ~~sales~~information ~~price~~available ~~since~~at ~~transportation~~the ~~costs~~time ~~downstream~~the estimates are made, estimates of ~~the~~future ~~wellhead~~cash flows are, ~~incurred~~ by ~~the~~nature, ~~Partnership’s~~highly ~~customers~~uncertain and ~~reflected~~may invary significantly from actual results. See Note 10, Impairment of Capitalized Costs to the ~~wellhead~~accompanying ~~price~~financial statements for additional disclosure related to the Partnership’s proved property impairment.

Oil Sales. Sales 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 determinable. The Partnership does not refine any of its oil production. The Partnership’s crude oil production is sold to purchasers at or near the Partnership’s wells under short-~~term~~ ~~purchase~~35 ~~contracts at prices and in accordance with arrangements that are customary in the oil industry.~~-

Table of Contents

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 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.

●· 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 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 32Financial -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 liabilities as well as the credit standing of derivative instrument counterparties. The Managing General Partner primarily uses 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 using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. The Managing General Partner has determined based on this evaluation, that the impact of nonperformance of the Partnership’s counterparties on the fair value of the Partnership’s derivative instruments is insignificant. 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.

~~Index~~- 36 -

~~Derivative~~Table ~~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 Partnership’s derivative assets from counterparties default, 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 on the fair value of the Partnership’s derivative instruments is not material. For the years ended December 31, 2009 and 2008, 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.Contents

Natural Gas and Oil Properties

The Partnership accounts for its natural gas and oil 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 additional reserve development.

The Partnership assesses impairment of capitalized costs of proved natural gas and oil properties, 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 management reasonably estimates commodities to be sold. The Partnership considers the receipt of the annual reserve report from independent engineers to be a triggering event. Therefore, impairment tests are completed as of December 31 each year. The estimates of future prices may differ from current market prices of natural gas and oil. 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 natural gas and oil properties. If during the completion of the impairment test, net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flow analysis, which is predominantly unobservable data or inputs (Level 3) and is measured by the amount by which the net capitalized costs exceed fair value. The Partnership’s estimated production used in the impairment testing is taken from the annual reserve report, which is summarized in the Supplemental Natural Gas and Oil Information–Unaudited, Net Proved Natural Gas and Oil Reserves that accompanies the financial statements included in this Annual Report. Estimated undiscounted future net cash flows are determined using prices from the forward price curve. Estimated discounted future net cash flows were determined utilizing a risk adjusted discount rate that is based on rates utilized by market participants that are commensurate with the risks inherent in the development of the underlying natural gas and oil reserves. The Partnership has incurred impairment losses from inception to December 31, 2009 of $8.7 million on its proved natural gas and oil properties, all of which was recognized in 2006.

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Index

Recent Accounting Standards

See Note 2, Summary of Significant Accounting Policies to the accompanying financial statements included in this Annual Report, for recently issued and implemented accounting standards including the SEC’s, Modernization of Oil and Gas Reporting, an effort by the SEC to provide investors with a more meaningful and comprehensive understanding of natural gas and oil reserves, that become effective for the Partnership’s financial statements and related disclosures for the year ending December 31, 2009. Since the SEC’s final rule prohibited retroactive application of the new industry accounting and reporting standards, the Partnership’s financial statements and related industry disclosures contained in this Annual Report for the year ending December 31, 2008, are based on those SEC standards then in effect, during the year 2008 and earlier.

~~The~~ITEM most significant provision of the new industry accounting and reporting final rule was the change in the method for determining the December 31, 2009 valuation price for in-ground natural gas and oil resources, used to determine economically producible natural gas and oil reserve quantities7A. ~~The~~QUANTITATIVE ~~2009~~AND ~~year-end~~QUALITATIVE ~~valuation~~DISCLOSURES ~~price~~ABOUT ~~was~~MARKET based on the application of the 12-month average of the first-day-of-the-month natural gas and oil commodity price during each month of 2009 while the 2008 year-end valuation price was based on the single-day natural gas and oil commodity price on December 31, 2008. 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. 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 $40,000. For more information regarding the Partnership’s natural gas and oil reserves for 2009 and 2008, see the Supplemental Natural Gas and Oil Information–Unaudited, Net Proved Natural Gas and Oil Reserves that accompanies the financial statements included in this Annual Report.RISK

A second provision of the SEC’s modernized oil and gas industry reporting rules is the revised definition for hydrocarbon resources classified as proved undeveloped reserves, or PUD’s. In order to substantiate natural gas and oil reserve quantities so categorized under the new rules, which may require a relatively major expenditure for their development, the Partnership is now required to have made a final investment decision to develop those additional reserves under a defined plan that is within five years of being initiated.

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. Although the new FASB accounting rule became effective for the Partnership’s quarterly and annual SEC reporting beginning September 30, 2009, for purposes of continuity and reader understanding of this comprehensive Annual Report for the years 2009 and 2008, accounting guidance referred to in footnotes and management’s discussion and analysis generally will utilize the Codification’s topical organization structure. Other than the manner in which accounting guidance is referenced, the Partnership’s adoption of the Codification had no impact on the Partnership’s accompanying financial statements or disclosure requirements.

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.

-ITEM 349. -CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

~~Index~~None.

~~Item~~ITEM 9.9A ~~Changes~~CONTROLS inAND ~~and Disagreements with Accountants on Accounting and Financial Disclosure~~PROCEDURES

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.

2007 Material Weaknesses

As discussed in the Management’s Report on Internal Control Over Financial Reporting included in the Partnership’s 2007 Annual Report on Form 10-K, the Partnership did not maintain effective internal controls over financial reporting as of December 31, 2007, with respect to the following three areas:

● The support for the Partnership’s general ledger depends in part on the effectiveness of controls of the Managing General Partner’s spreadsheets. The overall ineffectiveness of the Managing General Partner’s spreadsheet controls could have a material effect on the Partnership’s financial statements. The Partnership did not maintain effective controls to ensure the completeness, accuracy, and validity of key financial statement spreadsheets generated by the Managing General Partner. These spreadsheets are utilized by the Partnership to support significant balance sheet and income statement accounts. This material weakness has been remediated as of December 31, 2008.

● The support for the Partnership’s derivative calculations depends in part on the effectiveness of controls of the Managing General Partner’s process. The overall ineffectiveness of the Managing General Partner’s derivative controls could have a material effect on the Partnership’s financial statements. The Partnership did not maintain effective controls to ensure that the Managing General Partner had policies and procedures, or personnel with sufficient technical expertise to record derivative activities in accordance with generally accepted accounting principles. This material weakness has been remediated as of December 31, 2008.

● For the transactions that are directly related to and processed by the Partnership, 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.

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~~Index~~Table of Contents

(b) Management’s Report on Internal Control Over Financial 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(f) and 15d-15(f) as a process designed by, or under the supervision of, the 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 accordance with accounting principles generally accepted in the United States of America and includes those policies and procedures that:

(1)

Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the issuer;

(2)

Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with accounting principles generally accepted in the United States of America and that receipts and expenditures of the issuer are being made only in accordance with authorizations of management and directors of the issuer; and

(3)

Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the issuer’s assets that could have a material effect on the financial statements of the issuer.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate.

Management of the Managing General Partner has assessed the effectiveness of the Partnership’s internal control over financial reporting as of December 31, ~~2009~~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, ~~2009~~2010.

~~The~~Exchange ~~accompanying~~Act ~~Annual~~Rules ~~Report~~13a-15(c) onand ~~Form~~15d 10– 15(c) and Section 404 of the Sarbanes-KOxley ~~does~~Act ~~not~~of ~~include~~2002 require management of the Partnership to conduct an ~~attestation~~annual ~~report~~evaluation of the Partnership’s ~~independent~~internal ~~registered~~control ~~public~~over ~~accounting~~financial ~~firm~~reporting ~~regarding~~and to provide a report on management’s assessment, including a statement as to whether or not internal control over financial reporting ~~pursuant~~is toeffective. Since ~~Item~~the ~~308T~~Partnership (is neither an accelerated filer nor a~~)(4)~~ oflarge ~~Regulation~~accelerated Sfiler 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.

PDC, the Managing General Partner, ~~with~~made ~~participation~~no ~~from~~changes during the ~~Audit~~quarter ~~Committee~~ended ofDecember ~~its Board of Directors~~31, ~~addressed~~2010 ~~the material weaknesses disclosed~~ in the Partnership’s ~~2007 Annual Report on Form 10-K. The Managing General Partner believes that the effective implementation of changes in~~ internal ~~controls~~control over financial reporting, ~~during~~that ~~2008~~have ~~outlined~~materially ~~below,~~affected ~~remediated~~or ~~the~~are ~~first~~reasonably ~~two~~likely ~~known~~to ~~2007~~materially ~~material~~affect ~~weaknesses~~the ~~identified~~Partnership’s ~~above,~~internal ascontrol ofover ~~December~~financial ~~31, 2008~~reporting.

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Index

The Partnership made the following changes in its internal control over financial reporting of the Partnership (as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) during 2008.

● During the first quarter of 2008, the Managing General Partner implemented the general ledger, accounts receivable, cash receipts, revenue, financial reporting, and joint interest billing modules as part of a new broader financial system. The new financial system enhanced operating efficiencies and provided more effective management of Partnership business operations and processes. The Managing General Partner has taken the necessary steps to monitor and maintain appropriate internal controls during this period of change. These steps include documenting all new business process changes related to the new financial system; testing all new business processes on the new financial system; and conducting training related to the new business processes and to the new financial system software. The Managing General Partner expects the implementation of the new financial system will strengthen the overall systems of internal controls due to enhanced automation and integration of related processes. The Managing General Partner continues to modify the design and documentation of internal control processes and procedures related to the new financial system to supplement and complement existing internal controls over financial reporting. The system changes were developed to integrate systems and consolidate information, and were not undertaken in response to any actual or perceived deficiencies in the Partnership’s internal control over financial reporting. Testing of the controls related to this new system was included in the scope of the Managing General Partner’s assessment of the Partnership’s internal control over financial reporting for 2008.

● During the third quarter of 2008, the Managing General Partner improved controls over certain key financial statement spreadsheets that support all significant balance sheet and income statement accounts. Specifically, the Managing General Partner enhanced the spreadsheet policy to provide additional clarification and guidance with regard to risk assessment and enforced controls over: 1) the security and integrity of the data used in the various spreadsheets, 2) access to the spreadsheets, 3) changes to spreadsheet functionality and the related approval process and 4) increased management’s review of the spreadsheets.

● During the third quarter of 2008, in addition to accredited derivative training attended by key personnel, the Managing General Partner created and documented a desktop procedure to: 1) ensure the completeness and accuracy of the Managing General Partner’s derivative activities and 2) supplement key controls previously existing in the process. Further, the desktop procedure provides for a more robust review of the Managing General Partner’s derivative process. This procedure continued to be enhanced throughout the fourth quarter of 2008.

The Managing General Partner believes that the effective implementation of changes in internal controls over financial reporting during 2009 outlined below, remediated the third known 2007 material weakness identified above, as of December 31, 2009.

● During the first and second quarters of 2009, the Partnership developed a plan to improve controls 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’s derivative activities. Additionally, the Partnership completed the development of a revised financial close and reporting narrative that adequately describes the process, identifies key controls and assesses segregation of duties.

● In the third quarter, the Partnership developed documentation that describes the business processes and identifies key controls for internal control over financial reporting that assisted the Managing General Partner in adequately assessing internal control over financial reporting for the Partnership. In addition, the Partnership developed documentation and procedures to adequately assess segregation of duties. The controls and procedures were tested prior to December 31, 2009. At present, the Partnership has not quantified the total cost of this initiative; however, the majority of this cost is expected to be paid by the Managing General Partner.

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Index

(d) Other Changes in Internal Control over Financial Reporting

During 2009, PDC made the following changes in PDC’s internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934) that have materially affected or are reasonably likely to materially affect the Partnership’s internal control over financial reporting:

● 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. 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.

PDC, the Managing General Partner, made no changes in the Partnership’s internal control over financial reporting, as previously defined, during the quarters ended March 31 and June 30, 2010, that have materially affected or are reasonably likely to materially affect the Partnership’s internal control over financial reporting.

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 reporting. Further information regarding the material weaknesses of the Partnership referenced above may be found in the Partnership’s Annual Report on 10-K for the year ended December 31, 2007 under Item 9A (T), Controls and Procedures − Management’s Report on Internal Control Over Financial Reporting.

Item 9B.

Other Information

None.

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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 By-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 Managing General Partner’s Board seeks to understand and oversee critical business risks. Risks are considered in every business decision, not just through Board oversight of the Managing General Partner’s Risk Management system. The Board realizes, however, that it is not possible to eliminate all risk, nor is it desirable, and that appropriate risk-taking is essential to achieve the Managing General Partner’s objectives. The Board risk oversight structure provides that management report 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 but also PDC’s legal and regulatory compliance. The Board has created a Special Committee that has considered, upon Board request, the potential repurchase of certain of the sponsored drilling partnerships for which PDC serves as Managing General Partner. The Special Committee has not been asked to consider a repurchase of PDC 2003-D Limited Partnership at this time.

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:

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

●· Market-responsive natural gas and crude oil marketing and prudent field operations cost management which support 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 Partner ~~Relations~~relations.

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~~Index~~Table of Contents

Although the 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.

The Corporate Governance section of the Managing General Partner’s internet site contains additional information, including ~~PDC’s Certificate of Incorporation and~~ By-Laws, written charters for each Board committee and Board ~~policy~~corporate ~~statements.~~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.

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~~Index~~Table of Contents

Petroleum Development Corporation (dba PDC Energy)

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

Name	~~Age~~	Age	~~Positions and Offices Held~~	~~Director Since~~	Positions and Offices Held	~~Directorship Term Expires~~	Director Since	Directorship Term Expires
Richard W McCullough	58	59	~~Chairman and Chief Executive Officer~~	~~2007~~	Chairman and Chief Executive Officer	~~2013~~	2007	2013
Gysle R. Shellum	58	59	~~Chief Financial Officer~~	-	Chief Financial Officer	-	-	-
R. Scott Meyers	36	36	~~Chief Accounting Officer~~	-	Chief Accounting Officer	-	-	-
Barton R. Brookman, Jr.	48	48	~~Senior Vice President Exploration and Production~~	-	Senior Vice President Exploration and Production	-	-	-
Daniel W. Amidon	50	50	~~General Counsel and Secretary~~	-	General Counsel and Secretary	-	-	-
Lance Lauck	47	48	~~Senior Vice President Business Development~~	-	Senior Vice President Business Development	-	-	-
Joseph E. Casabona	67	67	~~Director~~	~~2007~~	Director	~~2011~~	2007	2011
Anthony J. Crisafio	57	58	~~Director~~	~~2006~~	Director	~~2012~~	2006	2012
Kimberly Luff Wakim	52		Director	2003		2012
Larry F. Mazza		50			Director		2007	2013
Larry F. Mazza	50		Director	2007		2013
David C. Parke		44			Director		2003	2011
David C. Parke	43		Director	2003		2011
Jeffrey C. Swoveland		56			Director		1991	2011
Jeffrey C. Swoveland	55		Director	1991		2011
James M. Trimble		62			Director		2009	2013
James M. Trimble	62		Director	2009		2013
Kimberly Luff Wakim		52			Director		2003	2012

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.

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

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~~Index~~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.

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

Joseph E. Casabona served as Executive Vice President and member of the Board of Directors of Denver-based Energy Corporation of America, a natural gas exploration and development company, from 1985 until his retirement in May 2007. Mr. Casabona’s responsibilities included strategic planning as well as executive oversight of drilling operations in the continental U.S. and internationally. InFrom 2008 through 2010, Mr. Casabona ~~became~~served as Chief Executive Officer of Paramax Resources Ltd, a junior public Canadian oil & gas company (PMXRF) engaged in the business of acquiring and exploration of oil and gas prospects, primarily in Canada and Idaho. Mr. Casabona serves as Chairman of the Planning and Finance Committee and serves on the Audit Committee.

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

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

Larry F. Mazza is President and Chief Executive Officer of MVB Bank, Inc. in Fairmont, West Virginia. He has been Chief Executive Officer since March 2005, and added the duties of President in January of 2009. Prior to 2005, Mr. Mazza served as Senior Vice President Retail Banking for BB&T and its predecessors in West Virginia, where he was employed from June 1986 to March 2005. A Certified Public Accountant for 26 years, Mr. Mazza also was previously an auditor with KPMG. Mr. Mazza serves on the Nominating and Governance Committee and the Compensation Committee.

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Index

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.

James M. Trimble has served as Managing Director 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 and development company focused primarily on drilling in mature basins in Texas, Louisiana and Oklahoma. From 2000 through 2004, Mr. Trimble was Chief Executive Officer of Elysium Energy and then Tex-~~Cal~~ ~~Energy~~42 LLC, both were privately held oil and gas companies that he was brought in to take through troubled workout solutions. Prior to this, he was Senior Vice President of Exploration and Production for Cabot Oil and Gas (NYSE:COG). From November 2002 until May 2006, he also served as a Director of Blue Dolphin Energy, an independent oil and gas company with operations in the Gulf of Mexico. Mr. Trimble serves on the Planning and Finance Committee and the Compensation Committee.-

Table of Contents

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

James M. Trimble has served as Managing Director 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 and development company focused primarily on drilling in mature basins in Texas, Louisiana and Oklahoma. From 2000 through 2004, Mr. Trimble was Chief Executive Officer of Elysium Energy and then Tex-Cal Energy LLC, both were privately held oil and gas companies that he was brought in to take through troubled workout solutions. Prior to this, he was Senior Vice President of Exploration and Production for Cabot Oil and Gas (NYSE:COG). From November 2002 until May 2006, he also served as a Director of Blue Dolphin Energy, an independent oil and gas company with operations in the Gulf of Mexico. Mr. Trimble serves on the Planning and Finance Committee and the Compensation Committee.

Audit Committee

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 employees or executives of its own. None of PDC’'s officers or directors receive any direct remuneration, compensation or reimbursement from the Partnership. These persons receive compensation solely from PDC. The Managing General Partner does not believe that PDC’s executive and non-executive compensation structure, available to officers or directors who act on behalf of the Partnership, is reasonably likely to have a 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. No management fee was paid to PDC in ~~2009~~2010 or ~~2008~~2009 as the Partnership 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 Item 13, Certain Relationships and Related Transactions, and Director Independence for a discussion of compensation paid by the Partnership to the Managing General Partner.

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~~Index~~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 ~~Stockholder~~STOCKHOLDER ~~Matters~~MATTERS

The following table presents information as of ~~June~~December 3031, 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~~		Number of Units Beneficially Owned		~~Percentage of Total Units Outstanding~~		Percentage of Total Units Outstanding		~~Percentage of Total Partnership Interests Beneficially Owned~~		Percentage of Total Partnership Interests Beneficially Owned
	~~1,749.84~~	1,749.84
Petroleum Development Corporation (2) (3) (4) (5)	-	-		~~41.84~~		43.90		~~2.39~~	%	2.51	%	~~1.91~~	%	2.01	%
Investor Partners beneficially owning 5% or more, of limited partner interests	-	-		-		-		-		-		-		-

(1) Additional general partner units were converted to limited partner interests at the completion of drilling activities. ~~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. [(4143.8490 units/1,749.84 units)*80% limited partnership ownership]

(5)

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

~~Item~~ITEM 13. ~~Certain~~CERTAIN ~~Relationships~~RELATIONSHIPS ~~and~~AND ~~Related~~RELATED ~~Transactions~~TRANSACTIONS, ~~and~~AND ~~Director~~DIRECTOR ~~Independence~~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.

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~~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.

Salary and employment benefit costs for the above specialized services are covered by the monthly fees paid to the Managing General Partner as more fully described in the preceding Item 11, Executive Compensation.

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

See Note 39, Transactions with Managing General Partner and Affiliates 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.

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Index

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 0.0144% to 0.0207% in 43 of the 45 wells owned by 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.

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.~~45 ~~Principal Accountant Fees and Services~~-

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)	$	~~105~~140,000	$	105,000
Tax Fees (2)		~~21,000~~-		1421,000
Total fees	$	~~126~~140,000	$	~~119~~126,000

(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 this 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.

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Index

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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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

10-K

000-50618

3.1

10/08/2010

3.2

Certificate of limited partnership which reflects the organization of the Partnership under West Virginia law

10-K

000-50618

3.2

10/08/2010

10.1

Drilling and operating agreement between the Partnership and PDC, as Managing General Partner

10-K

000-50618

10.1

10/08/2010

10.2

Form of assignment of leases to the Partnership

10-K

000-50618

10.2

10/08/2010

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing

Date

Filed

Herewith

10.3 Audited Consolidated Financial Statements for the year ended December 31, 2009 of Petroleum Development Corporation (dba PDC Energy) and its subsidiaries, as Managing General Partner of the Partnership 10-K 000-07246 03/04/2010

3.1	Limited Partnership Agreement	10-K	000-50618	3.1	10/12/2010

3.2	Certificate of limited partnership which reflects the organization of the Partnership under West Virginia law	10-K	000-50618	3.2	10/12/2010

10.1	Drilling and operating agreement between the Partnership and PDC, as Managing General Partner	10-K	000-50618	10.1	10/12/2010

10.2	Form of assignment of leases to the Partnership	10-K	000-50618	10.2	10/12/2010

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		02/24/2011

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	03/31/2009

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	03/31/2009

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	03/31/2009
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	03/31/2009
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	03/31/2009
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	03/31/2009
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 05/18/2009

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~~Index~~Table of Contents

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

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.

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

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing

Date

Filed

Herewith

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	03/31/2009

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	03/31/2009

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	05/18/2009

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~~Index~~Table of Contents

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

SEC File

Number

Exhibit

Filing

Date

Filed

Herewith

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.

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

99.2

Report of Independent Petroleum Consultants−Ryder Scott Company, LP

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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 2003-D 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

of Petroleum Development Corporation (dba PDC Energy)

~~October~~March 830, ~~2010~~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	~~Title~~	Date	~~Date~~
/s/ Richard W. McCullough	Chairman and Chief Executive Officer	~~Chairman and Chief Executive Officer~~	March 30, 2011	~~October 8, 2010~~
Richard W. McCullough	Petroleum Development Corporation (dba PDC Energy)	~~Petroleum Development Corporation (dba PDC Energy)~~
	Managing General Partner of the Registrant	~~Managing General Partner of the Registrant~~
	(Principal executive officer)	~~(Principal executive officer)~~
/s/ Gysle R. Shellum	Chief Financial Officer	~~Chief Financial Officer~~	March 30, 2011	~~October 8, 2010~~
Gysle R. Shellum	Petroleum Development Corporation (dba PDC Energy)	~~Petroleum Development Corporation (dba PDC Energy)~~
	Managing General Partner of the Registrant	~~Managing General Partner of the Registrant~~
	(Principal financial officer)	~~(Principal financial officer)~~
/s/ R. Scott Meyers	Chief Accounting Officer	~~Chief Accounting Officer~~	March 30, 2011	~~October 8, 2010~~
R. Scott Meyers	Petroleum Development Corporation (dba PDC Energy)	~~Petroleum Development Corporation (dba PDC Energy)~~
	Managing General Partner of the Registrant	~~Managing General Partner of the Registrant~~
	(Principal accounting officer)	~~(Principal accounting officer)~~
/s/ Kimberly Luff Wakim		Director		October 8, 2010
/s/ Joseph E. Casabona	Director		March 30, 2011
Kimberly Luff Wakim		Petroleum Development Corporation (dba PDC Energy)
Joseph E. Casabona	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant	~~Managing General Partner of the Registrant~~
/s/ Anthony J. Crisafio	Director	~~Director~~	March 30, 2011	~~October 8, 2010~~
Anthony J. Crisafio	Petroleum Development Corporation (dba PDC Energy)	~~Petroleum Development Corporation (dba PDC Energy)~~
	Managing General Partner of the Registrant	~~Managing General Partner of the Registrant~~
/s/ Jeffrey C. Swoveland	Director	~~Director~~	March 30, 2011	~~October 8, 2010~~
Jeffrey C. Swoveland	Petroleum Development Corporation (dba PDC Energy)	~~Petroleum Development Corporation (dba PDC Energy)~~
	Managing General Partner of the Registrant	~~Managing General Partner of the Registrant~~
/s/ Joseph E. Casabona		Director		October 8, 2010
/s/ Kimberly Luff Wakim	Director		March 30, 2011
Joseph E. Casabona		Petroleum Development Corporation (dba PDC Energy)
Kimberly Luff Wakim	Petroleum Development Corporation (dba PDC Energy)
	Managing General Partner of the Registrant	~~Managing General Partner of the Registrant~~

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~~Index~~Table of Contents

PDC 2003-D 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 Natural Gas and Oil Information - Unaudited		F-27
Supplemental Natural Gas, NGL and Crude Oil Information - Unaudited		F-22
Unaudited Condensed Quarterly Financial Statements:
Balance Sheets - 2009		F-30
Balance Sheets - 2008		F-31
Statements of Operations - 2009		F-32
Statements of Operations - 2008		F-33
Statements of Cash Flows - 2009		F-34
Statements of Cash Flows - 2008		F-35
Notes to Unaudited Condensed Quarterly Financial Statements		F-36

F-1

~~Index~~Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners of the PDC 2003-D Limited Partnership,

In our opinion, the accompanying balance sheets and the related statements of operations, partners’' equity and cash flows present fairly, in all material respects, the financial position of PDC 2003-D 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 October 8, 2010~~

Pittsburgh, Pennsylvania

March 30, 2011

F-2

~~Index~~Table of Contents

PDC 2003-D LIMITED PARTNERSHIP

Balance Sheets

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

	2009			2008
Assets	2010			2009
Assets
Current assets:
Cash and cash equivalents	$	~~107~~150,~~580~~881		$	~~106~~107,~~325~~580
Accounts receivable		~~182~~168,~~034~~646			~~197~~182,~~118~~034
Oil inventory		32,469			59,879
Crude oil inventory		48,686			32,469
Due from Managing General Partner-derivatives		~~332~~512,~~812~~519			1332,~~221,635~~812
Due from Managing General Partner-other, net		~~440,146~~-			1440,~~700,027~~146
Total current assets		1880,~~095,041~~732			31,~~284~~095,~~984~~041
Natural gas and oil properties, successful efforts method, at cost		26,982,833			26,806,261
Natural gas and crude oil properties, successful efforts method, at cost		19,903,098			26,982,833
Less: Accumulated depreciation, depletion and amortization		(1412,~~239~~070,~~379~~297	)		(1214,~~176~~239,~~388~~379	)
Natural gas and oil properties, net		12,743,454			14,629,873
Natural gas and crude oil properties, net		7,832,801			12,743,454
Due from Managing General Partner-derivatives		~~307~~829,~~821~~825			~~456~~307,~~025~~821
Other assets		5781,~~235~~116			3457,~~843~~235
Total noncurrent assets		138,~~108~~743,~~510~~742			1513,~~120~~108,~~741~~510
Total Assets	$	149,~~203~~624,~~551~~474		$	1814,~~405~~203,~~725~~551
Liabilities and Partners’ Equity
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	20104,~~551~~023		$	4320,~~787~~551
Due to Managing General Partner-derivatives		~~297~~430,~~960~~272			-297,960
Total current liabilities		318,511			43,787
Due to Managing General Partner-other, net		279,597			-
Due to Managing General Partner-derivatives		906,376			106,227
Total current liabilities		813,892			318,511
Asset retirement obligations		399,463			281,156
Due to Managing General Partner-derivatives		629,316			906,376
Total liabilities		1,624,350			431,170
Asset retirement obligations		423,763			399,463
Total liabilities		1,866,971			1,624,350
Commitments and contingent liabilities
Partners’ equity:
Partners' equity:
Managing General Partner		21,~~520~~556,~~829~~490			32,~~599~~520,~~900~~829
Limited Partners - 1,749.84 units issued and outstanding		106,~~058~~201,~~372~~013			1410,~~374~~058,~~655~~372
Total Partners’ equity		12,579,201			17,974,555
Total Partners' equity		7,757,503			12,579,201
Total Liabilities and Partners’ Equity	$	14,203,551		$	18,405,725
Total Liabilities and Partners' Equity	$	9,624,474		$	14,203,551

See accompanying notes to financial statements.

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PDC 2003-D 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	$	1,979,678		$	4,303,546
Natural gas, NGLs and crude oil sales	$	2,193,335		$	1,979,678
Commodity price risk management (loss) gain, net		(705,379	)		1,794,485
Commodity price risk management gain (loss), net		1,268,679			(705,379	)
Total revenues		13,~~274~~462,~~299~~014			61,~~098~~274,~~031~~299
Operating costs and expenses:
Natural gas and oil production costs		923,536			1,377,175
Natural gas, NGLs and crude oil production cost		1,420,756			923,536
Direct costs - general and administrative		82666,~~202~~746			5882,~~441~~202
Depreciation, depletion and amortization		21,~~062~~682,~~991~~408			12,~~639~~062,~~101~~991
Accretion of asset retirement obligations		6,761			15,288
Loss on impairment of natural gas and crude oil properties		3,242,907			-
Total operating costs and expenses		3,075,490			3,090,005
Accretion of asset retirement obligations		24,300			6,761
(Loss) income from operations		(1,801,191	)		3,008,026
Total operating costs and expenses		7,037,117			3,075,490
Interest expense		(5,404	)		-
Loss from operations		(3,575,103	)		(1,801,191	)
Interest income		42,935			75,446
Interest expense		-			(5,404	)
Net (loss) income	$	(1,763,660	)	$	3,083,472
Interest income		178			42,935
Net (loss) income allocated to partners	$	(1,763,660	)	$	3,083,472
Net loss	$	(3,574,925	)	$	(1,763,660	)
Less: Managing General Partner interest in net (loss) income		(352,732	)		616,694
Net loss allocated to partners	$	(3,574,925	)	$	(1,763,660	)
Net (loss) income allocated to Investor Partners	$	(1,410,928	)	$	2,466,778
Less: Managing General Partner interest in net loss		(714,985	)		(352,732	)
Net (loss) income per Investor Partner unit	$	(806	)	$	1,410
Net loss allocated to Investor Partners	$	(2,859,940	)	$	(1,410,928	)
Net loss per Investor Partner unit	$	(1,634	)	$	(806	)
Investor Partner units outstanding		1,749.84			1,749.84

See accompanying notes to financial statements.

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PDC 2003-D 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		14,532,462			3,639,349			18,171,811
Balance, December 31, 2008	$	14,374,655		$	3,599,900		$	17,974,555
Distributions to partners		(2,624,585	)		(656,143	)		(3,280,728	)
Net income		2,466,778			616,694			3,083,472
Balance, December 31, 2008		14,374,655			3,599,900			17,974,555
Distributions to partners		(2,905,355	)		(726,339	)		(3,631,694	)
Net loss		(1,410,928	)		(352,732	)		(1,763,660	)
Balance, December 31, 2009	$	10,058,372		$	2,520,829		$	12,579,201
Distributions to partners		(997,419	)		(249,354	)		(1,246,773	)
Net loss		(2,859,940	)		(714,985	)		(3,574,925	)
Balance, December 31, 2010	$	6,201,013		$	1,556,490		$	7,757,503

See accompanying notes to financial statements.

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PDC 2003-D 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	$	(1,763,660	)	$	3,083,472
Net loss	$	(3,574,925	)	$	(1,763,660	)
Adjustments to net (loss) income to reconcile to net cash provided by operating activities:
Adjustments to net loss to reconcile to net cash provided by operating activities:
Depreciation, depletion and amortization		21,~~062~~682,~~991~~408			12,~~639~~062,~~101~~991
Accretion of asset retirement obligations		624,~~761~~300			156,~~288~~761
Unrealized loss (gain) on derivative transactions		2,135,136			(1,663,331	)
Unrealized (gain) loss on derivative transactions		(846,459	)		2,135,136
Loss on impairment of natural gas and crude oil properties		3,242,907			-
Changes in operating assets and liabilities:
Decrease in accounts receivable		1513,~~084~~388			~~223~~15,~~567~~084
Decrease (increase) in oil inventory		27,410			(59,879	)
(Increase) decrease in crude oil inventory		(16,217	)		27,410
Increase in other assets		(2223,~~392~~881	)		(2422,~~555~~392	)
Decrease in accounts payable and accrued expenses		(23,236	)		(1,481	)
Increase (decrease) in accounts payable and accrued expenses		83,472			(23,236	)
Decrease in due from Managing General Partner, other - net		1,259,881			103,374
Decrease in due from Managing General Partner, Net		440,146			1,259,881
Net cash provided by operating activities		3,697,975			3,315,556
Increase in due to Managing General Partner, Net		279,597			-
Net cash provided by operating activities		1,304,736			3,697,975
Cash flows from investing activities:
Capital expenditures for oil and gas properties		(65,026	)		(23,394	)
Capital expenditures for natural gas and crude oil properties		(14,662	)		(65,026	)
Net cash used in investing activities		(6514,~~026~~662	)		(2365,~~394~~026	)
Cash flows from financing activities:
Distributions to Partners		(31,~~631~~246,~~694~~773	)		(3,~~280~~631,~~728~~694	)
Net cash used in financing activities		(31,~~631~~246,~~694~~773	)		(3,~~280~~631,~~728~~694	)
Net increase in cash and cash equivalents		143,~~255~~301			111,~~434~~255
Cash and cash equivalents, beginning of year		~~106~~107,~~325~~580			94106,~~891~~325
Cash and cash equivalents, end of year	$	~~107~~150,~~580~~881		$	~~106~~107,~~325~~580
Supplemental cash flow information:
Cash payments for:
Interest	$	~~5,404~~-		$	-5,404
Supplemental disclosure of non-cash activity:
Asset retirement obligation, with corresponding increase to oil and gas properties	$	111,546		$	-
Asset retirement obligation, with corresponding increase to natural gas and crude oil properties	$	-		$	111,546

See accompanying notes to financial statements.

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PDC 2003-D LIMITED PARTNERSHIP

Notes to Financial Statements

~~Note~~NOTE 1 –- ~~General~~GENERAL

PDC 2003-D Limited Partnership (the “Partnership” or the “Registrant”) was organized as a limited partnership, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of natural gas and crude oil properties. Business operations of the Partnership commenced upon closing of an offering for the sale of Partnership units. Upon funding, the Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner which authorizes Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, to conduct and manage the Partnership’s business. Upon completion of the drilling phase of the Partnership’s wells, all additional general partners units were converted into units of limited partner interests and thereafter became limited partners of the Partnership. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner is authorized to manage all activities of the Partnership and initiates and completes substantially all Partnership transactions. As of June 30, 2010, there were 1,227 Investor Partners. Petroleum Development Corporation (dba PDC Energy) is the designated Managing General Partner of the Partnership and owns a 20% Managing General Partner ownership in the Partnership. According to the terms of the Limited Partnership Agreement, revenues, costs and cash distributions of the Partnership are allocated 80% to the limited partners (“Investor Partners”), which are shared pro rata, based upon the number of units in the Partnership, and 20% to the Managing General Partner. Through June 30, 2010, the Managing General Partner has repurchased 41.84 units of Partnership interests from Investor Partners at an average price of $5,749 per unit. The following table presents Partnership formation and organization information through the completion of the drilling phase on September 29, 2004:

				Number of Partner Units
PDC 2003-D Limited Partnership Information	Date	Number of Partners		Additional General Partner Units			Limited Partner Units		Equity Percentage			Amount (millions)
West Virginia Limited Partnership Formation	September 25, 2003
Limited Partnership Termination Date	December 31, 2050
Public Sale of Securities and Funding	December 15, 2003
Investor Partners (1) Unit Cost: $20,000			1,123		1,735.34			14.50		80.00	%	$	35.0
PDC, Managing General Partner										20.00	%		7.6
Total funding													42.6
Syndication costs paid to third-party brokers													(3.7	)
Management Fee Paid to PDC													(0.9	)
Net funding available for drilling activities										100.00	%	$	38.0
Conversion of additional General Partners to Limited Partners	September 29, 2004				(1,735.34	)		1,735.34
Limited Partnership Units after Conversion					-			1,749.84

As of December 31, 2010, there were 1,223 Investor Partners. PDC is the designated Managing General Partner of the Partnership and owns a 20% Managing General Partner ownership in the Partnership. According to the terms of the Limited Partnership Agreement, revenues, costs and cash distributions of the Partnership are allocated 80% to the limited partners (“Investor Partners”), which are shared pro rata, based upon the number of units in the Partnership, and 20% to the Managing General Partner. Through December 31, 2010, the Managing General Partner has repurchased 43.90 units of Partnership interests from Investor Partners at an average price of $5,637 per unit. As of December 31, 2010, the Managing General Partner owns 22.0% of the Partnership.

~~(1)~~ The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual investor partner. For more information about the Managing General Partner’s limited partner unit repurchase program, see Note 68, Partners’ Equity and Cash Distributions.

~~Executive~~NOTE ~~Drilling~~2 ~~Program~~- ~~Executive~~SUMMARY ~~officers~~OF ofSIGNIFICANT ~~the~~ACCOUNTING 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.POLICIES

Management’s Estimates

The preparation of the Partnership’s financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S.”) requires the Partnership to make estimates and assumptions that affect the amounts reported in the Partnership’s financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to the financial statements include estimates of natural gas, natural gas liquids (“NGL”) and crude oil sales revenue, natural gas, NGLs and crude oil reserves, future cash flows from natural gas and crude oil properties and valuation of derivative instruments.

Basis of Presentation

The financial statements include only those assets, liabilities and results of operations of the partners which relate to the business of the Partnership.

Cash and Cash Equivalents. The Partnership considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Partnership maintains substantially all of its cash and cash equivalents in a bank account at one financial institution. The balance in the Partnership’s account is insured by Federal Deposit Insurance Corporation, or FDIC, up to $250,000 through December 31, 2013. The Partnership has not experienced losses in any such accounts to date and limits the Partnership’s exposure to credit loss by placing its cash and cash equivalents with high-quality financial institutions.

Accounts Receivable and Allowance for Doubtful Accounts. The Partnership’s accounts receivable are from purchasers of natural gas, NGLs and crude oil production. The Partnership sells substantially all of its natural gas, NGLs and crude oil to customers who purchase natural gas, NGLs and crude oil from other partnerships managed by the Partnership’s Managing General Partner. The Managing General Partner periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of its customers. No allowance was deemed necessary at December 31, 2010 or 2009.

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PDC 2003-D LIMITED PARTNERSHIP

Notes to Financial Statements

	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 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 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 0.0144% to 0.0207% in 43 of the 45 wells owned by 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.
Note 2 - Summary of Significant Accounting Policies
	Basis of Presentation
	The financial statements include only those assets, liabilities and results of operations of the partners which relate to the business of the Partnership.
	Cash and Cash Equivalents
	The Partnership considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Partnership maintains substantially all of its cash and cash equivalents in a bank account at one financial institution. Prior to October 3, 2008, the balance in the Partnership’s account was insured by Federal Deposit Insurance Corporation, or FDIC, up to $100,000. As a result of the Emergency Economic Stability Act, the FDIC limit was raised to $250,000 effective October 3, 2008 through December 31, 2009 and subsequently extended through December 31, 2013. The Partnership has not experienced losses in any such accounts to date and limits the Partnership’s exposure to credit loss by placing its cash and cash equivalents with high-quality financial institutions.
	Accounts Receivable and Allowance for Doubtful Accounts
	The Partnership’s accounts receivable are from purchasers of natural gas and oil production. The Partnership sells substantially all of its natural gas and oil to customers who purchase natural gas and oil from other partnerships managed by the Partnership’s Managing General Partner. Inherent to the Partnership’s industry is the concentration of natural gas and oil sales made to few customers. This industry concentration has the potential to impact the Partnership’s overall exposure to credit risk, either positively or negatively, in that its customers may be similarly affected by changes in economic, industry or other conditions.
	As of December 31, 2009 and 2008, the Partnership did not record an allowance for doubtful accounts. 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 Managing General Partner periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of its customers. The Partnership did not incur any losses on accounts receivable for the years ended December 31, 2009 and 2008. 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.
	Commitments
	As Managing General Partner, PDC maintains performance bonds in the form of certificates of deposit for plugging, reclaiming and abandoning of the Partnership’s wells as required by governmental agencies. If a government agency were required to access these performance bonds to cover plugging, reclaiming or abandonment costs on a Partnership well, the Partnership would be obligated to fund any amounts in excess of funds previously withheld by the Managing General Partner to cover these expenses.

Commitments. As Managing General Partner, PDC maintains performance bonds in the form of certificates of deposit for plugging, reclaiming and abandoning of the Partnership’s wells as required by governmental agencies. If a government agency were required to access these performance bonds to cover plugging, reclaiming or abandonment costs on a Partnership well, the Partnership would be obligated to fund any amounts in excess of funds previously withheld by the Managing General Partner to cover these expenses.

Inventory. Inventory consists of crude oil, stated at the lower of cost to produce or market.

Derivative Financial Instruments. The Partnership is exposed to the effect of market fluctuations in the prices of natural gas and crude oil. The Managing General Partner employs established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. The Managing General Partner’s policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes.

All derivative assets and liabilities are recorded on the balance sheets at fair value. PDC, as Managing General Partner, has elected not to designate any of the Partnership’s derivative instruments as hedges. Accordingly, changes in the fair value of the Partnership’s derivative instruments are recorded in the Partnership’s statements of operations and the Partnership’s net income is subject to greater volatility than if the Partnership’s derivative instruments qualified for hedge accounting. Changes in the fair value of derivative instruments related to the Partnership’s natural gas and crude oil sales are recorded in the line captioned, “Commodity price risk management gain (loss), net.” As positions designated to the Partnership settle, the realized gains and losses are netted for distribution. Net realized gains are paid to the Partnership and net realized losses are deducted from the Partnership’s cash distributions generated from production. The Partnership bears its designated share of counterparty risk.

Validation of a contract’s fair value is performed internally. While the Managing General Partner uses common industry practices to develop the Partnership’s valuation techniques, changes in the Partnership’s pricing methodologies or the underlying assumptions could result in significantly different fair values. See Note 3, Fair Value of Financial Instruments and Note 4, Derivative Financial Instruments, for a discussion of the Partnership’s derivative fair value measurements and a summary fair value table of open positions as of December 31, 2010 and 2009.

Natural Gas and Crude Oil Properties. Significant accounting polices related to the Partnership’s properties and equipment are discussed below.

The Partnership accounts for its natural gas and crude oil properties (the “Properties”) under the successful efforts method of accounting. Costs of proved developed producing properties and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. The Partnership calculates quarterly depreciation, depletion and amortization ("DD&A") expense by using as the denominator the Partnership’s estimated quarter-end reserves adjusted to add back current period production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the statement of operations as a gain or loss. Upon the sale of individual wells, the proceeds are credited to accumulated DD&A. See Supplemental Natural Gas, NGL and Crude Oil Information – Unaudited, Net Proved Reserves for additional information regarding the Partnership’s reserve reporting. In accordance with the Agreement, all capital contributed to the Partnership after deducting syndication costs and a one-time management fee was used solely for the drilling of natural gas and crude oil wells. Accordingly, all such funds were advanced to the Managing General Partnership as of the last day of the year in which the Partnership was formed. The Partnership does not maintain an inventory of undrilled leases.

Proved Reserves. Partnership estimates of proved reserves are based on those quantities of natural gas, NGLs and crude oil which, by analysis of geoscience and engineering data, are estimated with reasonable certainty to be economically producible in the future from known reservoirs under existing conditions, operating methods and government regulations. Annually, the Managing General Partner engages independent petroleum engineers to 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.

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PDC 2003-D LIMITED PARTNERSHIP

Notes to Financial Statements

~~Inventories~~Proved ~~Oil~~Property ~~inventories are stated at the lower of average lifting cost or market~~Impairment. ~~Natural Gas and Oil Properties~~ The Partnership ~~accounts~~assesses ~~for~~ its ~~natural gas and oil properties (the “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~~crude ~~reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved natural gas and~~ oil reserves. See Supplemental Natural Gas and Oil Information – Unaudited, Net Proved Natural Gas and Oil Reserves for additional information regarding the Partnership’s reserve reporting. In accordance with the Agreement, all capital contributed to the Partnership after deducting syndication costs and a one-time management fee was used solely for the drilling of natural gas and oil wells. Accordingly, all such funds were advanced to the Managing General Partnership as of the last day of the year in which the Partnership was formed. The Partnership does not maintain an inventory of undrilled leases. Partnership estimates of proved reserves are based on those quantities of natural gas and 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 natural gas and oil reserves~~ for major well rework or abandonment during the year as needed. 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 reported reserve estimates represent our 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 our 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. The Partnership assesses impairment ~~of capitalized costs of proved natural gas and oil properties~~, 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 ~~management~~the ~~reasonably~~Managing ~~estimates~~General ~~commodities~~Partner toreasonably beestimates ~~sold. The Partnership considers~~ the ~~receipt~~commodities ~~of the annual reserve report from independent engineers~~ to be ~~a triggering event~~sold. ~~Therefore, impairment tests are completed as of December 31 each year.~~ The estimates of future prices may differ from current market prices of natural gas, NGLs and crude oil. Certain ~~Downward~~events, including but not limited to, downward revisions in estimates ofto the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of the Partnership’s proved natural gas and crude oil properties. If ~~during the completion of the impairment test,~~ net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash ~~flow~~flows analysis, which is predominantly unobservable data or inputs (Level 3) , and is measured by the amount by which the net capitalized costs exceed their fair value. The Partnership’s estimated production used in the impairment testing is taken from the annual reserve report, which is presented in the Supplemental Natural Gas and Oil Information–Unaudited, Net Proved Natural Gas and Oil Reserves. Estimated undiscounted future net cash flows are determined using prices from the forward price curve. at the measurement date. Estimated discounted future net cash flows ~~were~~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 ~~oil~~natural gas and ~~natural~~crude ~~gas~~oil properties for impairment at December 31, ~~2009.~~2010 ~~The Partnership recognized no impairment of its natural gas~~ and ~~oil properties for the year ended December 31,~~ 2009 ~~or 2008~~. See ~~The~~Note ~~Partnership has incurred impairment losses from inception to December 31~~10, ~~2009~~Impairment of ~~$8,674,280~~Capitalized onCosts ~~its~~for ~~proved~~additional ~~natural~~disclosure ~~gas~~related ~~and~~to ~~oil~~the ~~properties,~~Partnership’s ~~all~~proved ofproperty ~~which, was recognized in 2006~~impairment.

Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which the Partnership produces natural gas, NGLs and crude oil. The Partnership’s share of these taxes is expensed to the account “Natural gas, NGLs and crude oil production costs.” The Partnership’s production taxes payable are included in the caption “Accounts payable and accrued expenses” on the Partnership’s balance sheets.

Income Taxes. Since the taxable income or loss of the Partnership is reported in the separate tax returns of the individual investor partners, no provision has been made for income taxes by the Partnership.

Asset Retirement Obligations. The Partnership accounts for asset retirement obligations by recording the fair value of Partnership well plugging and abandonment obligations when incurred, which is at the time the well is spudded. Upon initial recognition of an asset retirement obligation, the Partnership increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in present value. The initial capitalized costs are depleted over the useful lives of the related assets, through charges to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling retirement obligations. See Note 6, Asset Retirement Obligations for a reconciliation of the changes in the Partnership’s asset retirement obligation from January 1, 2009, to December 31, 2010.

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PDC 2003-D LIMITED PARTNERSHIP

Notes to Financial Statements

Revenue Recognition . Natural ~~Gas~~gas, ~~Sales.~~NGLs ~~Sales~~and ofcrude ~~natural~~oil ~~gas~~revenues are recognized when ~~natural~~production ~~gas~~is ~~has~~sold ~~been delivered~~ to a ~~custody~~purchaser ~~transfer~~at ~~point,~~a ~~persuasive~~fixed ~~evidence~~or ofdeterminable aprice, ~~sales~~delivery ~~arrangement~~has ~~exists~~occurred, ~~the~~ rights and responsibility of ownership ~~pass~~have totransferred ~~the~~and ~~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. 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 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 ~~Oil~~majority ~~Sales. Sales~~ of ~~oil are recognized when persuasive evidence of a sales arrangement exists,~~ the ~~oil~~Partnership’s isnatural ~~verified as produced and is delivered from storage tanks at well locations to a purchaser~~gas, ~~collection~~NGLs ~~of revenue from the sale is reasonably assured~~ and the sales price is determinable. 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 crude oil ~~production~~ is sold toby ~~purchasers at or near~~ the ~~Partnership’s~~Managing ~~wells~~General Partner under ~~short-term purchase~~ contracts ~~at prices and in accordance~~ with ~~arrangements~~terms ~~that~~ranging ~~are customary in the oil industry. The Partnership presents any taxes collected~~ from ~~customers~~one ~~and~~month ~~remitted~~up to a government agency on a net basis in its statements of operations in accordance with accounting standards for revenue recognition regarding taxes collected from customers and remitted to governments. Asset Retirement Obligations The Partnership accounts for asset retirement obligations by recording the ~~fair~~life ~~value~~ of ~~Partnership well plugging and abandonment obligations when incurred, which is at~~ the ~~time the~~ well ~~is spudded~~. Virtually ~~Upon~~all ~~initial recognition~~ of ~~an asset retirement obligation,~~ the ~~Partnership~~Managing ~~increases~~General ~~the~~Partner’s ~~carrying~~contract ~~amount~~pricing ofprovisions ~~the long-lived asset by the same amount as the liability. The asset retirement obligations~~ are ~~accreted,~~tied ~~over the estimated life of the related asset, for the change in present value. The initial capitalized costs are depleted over the useful lives of the related assets, through charges~~ to ~~DD&A~~a ~~expense.~~market Ifindex ~~the~~with ~~fair~~certain ~~value~~adjustments ofbased ~~the estimated asset retirement obligation changes~~on, anamong ~~adjustment~~other ~~is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates~~factors, ~~escalating~~whether ~~costs~~a ~~for future dismantlement, restoration, reclamation and abandonment and changes in the estimate of retirement obligation settlement at the end of each~~ well’s ~~productive~~delivers ~~service~~to ~~life. See Note 8, Asset Retirement Obligations for~~ a ~~reconciliation~~gathering ofor ~~asset~~transmission ~~retirement~~line, ~~obligation~~quality ~~activity. Derivative Financial Instruments The Partnership is exposed to the effect~~ of ~~market fluctuations in the prices of~~ natural gas and ~~oil.~~prevailing ~~Price~~supply ~~risk represents the potential risk of loss from adverse changes in the market price of natural gas~~ and ~~oil~~demand ~~commodities~~conditions. The Managing General Partner employs established policies and procedures to manage the risks associated with these market fluctuations using commodity derivative instruments. The Managing General Partner’s policy prohibits the use of natural gas and oil derivative instruments for speculative purposes.

Recent Accounting Standards.

The following standards have been recently adopted:

Fair Value Measurements and Disclosures. In January 2010, the Financial Accounting Standards Board (“FASB”) issued changes clarifying existing disclosure requirements related to fair value measurements. The update also added a new requirement to disclose fair value transfers in and out of Levels 1 and 2 and describe the reasons for the transfers. The adoption of these changes as of January 1, 2010, did not have a material impact on the Partnership’s accompanying financial statements.

The following standards have been recently issued:

Fair Value Measurements and Disclosures. In January 2010, the FASB issued changes clarifying existing disclosure requirements and requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements. The update also added a new requirement to disclose fair value transfers in and out of Levels 1 and 2 and describe the reasons for the transfers. These changes will be effective for the Partnership’s financial statements issued for the first interim or annual reporting period beginning after December 15, 2009, except for gross presentation of the Level 3 roll forward, which will become effective for annual reporting periods beginning after December 15, 2010. The Partnership’s adoption did not have a material effect on the Partnership’s financial statements and related disclosures.

Internal Control over Financial Reporting in Exchange Act Periodic Reports. By Final Rule effective September 21, 2010, the SEC amended its rules and forms to conform them to Section 404(c) of the Sarbanes-Oxley Act of 2002, or SOX, as added by the Dodd-Frank Wall Street Reform and Consumer Protection Act. The new SEC rules permanently exempt the Partnership, as a smaller reporting company filer, from the SOX requirement that registrants obtain and include in their annual report, filed with the SEC, their independent registered public accounting firm’s attestation report on the effectiveness of the registrant’s internal controls over financial reporting.

Subsequent Events. The Managing General Partner has evaluated the Partnership’s activities subsequent to December 31, 2010 through the issuance of the financial statements, and has concluded that no material subsequent events have occurred that would require additional recognition in the Partnership’s financial statements or disclosure in the notes to the Partnership’s financial statements.

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~~Index~~Table of Contents

PDC 2003-D LIMITED PARTNERSHIP

Notes to Financial Statements

~~All~~NOTE ~~derivative~~3 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 (loss) gain, net.” Validation of a contract’s fair value is performed internally. While the Managing General Partner uses common industry practices to develop the Partnership’s valuation techniques, changes in the Partnership’s pricing methodologies or the underlying assumptions could result in significantly different fair values. See Note 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. Income Taxes Since the taxable income or loss of the Partnership is reported in the separate tax returns of the individual investor partners, no provision has been made for income taxes by the Partnership. Production Tax Liability The Partnership is responsible for production taxes which are primarily made up of severance and property taxes to be paid to the states and counties in which the Partnership produces natural gas and oil. The Partnership’s share of these taxes is expensed to the account “Natural gas and 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. Use of Estimates The Partnership has made a number of estimates and assumptions relating to the reporting of assets and liabilities and revenues and expenses and the disclosure of contingent assets and liabilities to prepare these Partnership financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates. Estimates which are particularly significant to the financial statements include estimates of natural gas and oil reserves, future cash flows from natural gas and oil properties which are used in assessing impairment of long-~~lived~~ ~~assets,~~FAIR ~~estimated~~VALUE ~~production~~OF ~~and~~FINANCIAL severance taxes, asset retirement obligations, and valuation of derivative instruments. 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 United States of America Generally Accepted Accounting Principles (“U. S. GAAP”). Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for Securities and Exchange, or 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.INSTRUMENTS

Derivative Financial Instruments

Determination of Fair Value. The Partnership’s fair value measurements are estimated pursuant to a fair value hierarchy that requires the Partnership to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:

Level 1 – Quoted prices (unadjusted) in active markets for identical assets or liabilities. Included in Level 1 are the Partnership’s commodity derivative instruments for New York Mercantile Exchange, or NYMEX, based natural gas swaps.

Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means.

Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Included in Level 3 are the Partnership’s commodity derivative instruments for Colorado Interstate Gas, or CIG, based natural gas swaps, crude oil swaps, natural gas and crude oil collars and the Partnership’s natural gas basis protection derivative instruments.

Derivative Financial Instruments. The Partnership measures the fair value of its derivative instruments based upon quoted market prices, where available. The valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions. The methods described above may produce a fair value calculation that may not be indicative of future fair values. The Managing General’s valuation determination also gives consideration to nonperformance risk on Partnership liabilities in addition to nonperformance risk on PDC’s own business interests and liabilities, as well as the credit standing of derivative instrument counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in the Managing General Partner’s credit facility agreement, as counterparties to the Managing General Partner’s derivative contracts. The Managing General Partner has evaluated the credit risk of the counterparties holding the Partnership’s derivative assets using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on the Managing General Partner’s evaluation, the Managing General Partner has determined that the impact of the nonperformance of the counterparties on the fair value of the Partnership’s derivative instruments is insignificant. Validation of Partnership’s contracts’ fair value is performed internally and while the Managing General Partner uses common industry practices to develop its valuation techniques, changes in the Managing General Partner’s pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes these valuation methods are appropriate and consistent with those used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value. For more information concerning the Partnership’s concentration of credit risk and the Managing General Partner’s evaluation of that risk, see Note 5, Concentration of Risk, below.

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~~Index~~Table of Contents

PDC 2003-D LIMITED PARTNERSHIP

Notes to Financial Statements

Business Combinations
In December 2007, the FASB revised guidance for business combinations, goodwill and other intangible assets by requiring the use of the acquisition method for business combinations whose acquisition date is on or after January 1, 2009, with earlier adoption prohibited. The income tax provisions became effective as of that date for all acquisitions, regardless of the acquisition date. The new guidance, as subsequently amended in April 2009, requires:
	●	An acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their acquisition-date fair values.
	●	The disclosure of the information necessary for investors and other users to evaluate and understand the nature and financial effect of the business combination.
	●	Acquisition-related costs are to be expensed as incurred.
	●	Certain acquired contingencies are to be treated as contingent consideration and measured both initially and subsequently at fair value, if fair value can be reasonably estimated.
The FASB’s comprehensive revised guidance for business combinations also amends other related authoritative guidance including:
	●	Accounting for income taxes, to require the acquirer to recognize changes in the amount of its deferred tax benefits recognizable due to a business combination either in income from continuing operations in the period of the combination or directly in contributed capital, depending on the circumstances.
	●	Accounting for uncertainty in income taxes, to require, subsequent to a prescribed measurement period, changes to acquisition-date income tax uncertainties to be reported in income from continuing operations and changes to acquisition-date acquiree deferred tax benefits to be reported in income from continuing operations or directly in contributed capital, depending on the circumstances.
The Partnership adopted these provisions effective January 1, 2009, for which the provisions will be applied prospectively in the Partnership’s accounting for future acquisitions, if any. The adoption had no impact on the Partnership’s financial statements.
Consolidation – Non-controlling Interests
In December 2007, the FASB issued, in conjunction with the revised standards for business combinations previously noted, revised guidance regarding non-controlling interests in consolidated financial statements that requires the accounting and reporting for minority interests to be recharacterized as non-controlling interests and classified as a component of equity. Additionally, the revised standards establish reporting requirements for sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners. The Partnership adopted the provisions of this revised standard effective January 1, 2009. The adoption had no impact on the Partnership’s financial statements.
Derivatives and Hedging Disclosures
In April 2007, the FASB issued an accounting directive regarding the conditions when offsetting of fair value amounts for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) arising from the same master netting arrangement for derivative instruments, is permissible. This new accounting principle applied to fiscal years beginning after November 15, 2007, with early adoption permitted. The January 1, 2008 adoption of this directive had no impact on the Partnership’s financial statements.

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

	Level 1			Level 3			Total

As of December 31, 2009
Assets:
Commodity based derivatives	$	311,686		$	328,947		$	640,633
Total assets		311,686			328,947			640,633

Liabilities:
Commodity based derivatives		(20,235	)		(78,306	)		(98,541	)
Basis protection derivative contracts		-			(1,105,795	)		(1,105,795	)
Total liabilities		(20,235	)		(1,184,101	)		(1,204,336	)

Net asset (liability)	$	291,451		$	(855,154	)	$	(563,703	)

As of December 31, 2010
Assets:
Commodity based derivatives	$	1,287,909		$	54,435		$	1,342,344
Total assets		1,287,909			54,435

Filing Compare · PDC 2003-D LP